UNITED
      STATES


SECURITIES
      AND EXCHANGE COMMISSION


Washington,
      D.C. 20549





**FORM
      10-Q**





x**QUARTERLY
      REPORT PURSUANT TO SECTION 13 OR 15(d)**


**OF
      THE SECURITIES EXCHANGE ACT OF 1934**





For
      the
      quarterly period ended September 30, 2007





OR





o**TRANSITION
      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
            o
            No
            x







Indicate
      by check mark whether each registrant is a large accelerated filer, an
      accelerated filer, or a non-accelerated filer. See definition of “accelerated
      filer” and “large accelerated filer” in Rule 12b-2 of the Exchange
      Act.:





Progress
                Energy
            Large
                accelerated filer
            x
            Accelerated
                filer
            o
            Non-accelerated
                filer
            oPEC
            Large
                accelerated filer
            o
            Accelerated
                filer
            o
            Non-accelerated
                filer
            xPEF
            Large
                accelerated filer
            o
            Accelerated
                filer
            o
            Non-accelerated
                filer
            x





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, 2007, each registrant had the following shares of common stock
      outstanding:





**Registrant**
            **Description**
            **Shares**Progress
                Energy
            Common
                Stock (Without Par Value)
            259,201,899PEC
            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 CONTENTS**





GLOSSARY
      OF TERMS





SAFE
      HARBOR FOR FORWARD-LOOKING
      STATEMENTS





**PART
      I.  FINANCIAL INFORMATION**





Item
      1.              Financial Statements





Unaudited
      Interim Financial Statements:





**Progress
      Energy, Inc. (Progress Energy)**


Unaudited
      Consolidated Statements of
      Income


Unaudited
      Consolidated Balance
      Sheets


Unaudited
      Consolidated Statements of Cash
      Flows





**Carolina
      Power & Light Company**


**d/b/a
      Progress Energy Carolinas, Inc. (PEC)**


Unaudited
      Consolidated Statements of
      Income


Unaudited
      Consolidated Balance
      Sheets


Unaudited
      Consolidated Statements of Cash
      Flows





**Florida
      Power Corporation**


**d/b/a
      Progress Energy Florida, Inc. (PEF)**


Unaudited
      Statements of Income


Unaudited
      Balance Sheets


Unaudited
      Statements of Cash Flows





Combined
      Notes to Unaudited 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 Operations





Item
      3.              Quantitative and Qualitative Disclosures
      about Market
      Risk





Item
      4.              Controls and Procedures





**PART
      II.  OTHER INFORMATION**





Item
      1.              Legal Proceedings





Item
      1A.           Risk Factors





Item
      2.              Unregistered Sales of Equity Securities
      and Use of
      Proceeds





Item
      6.              Exhibits





SIGNATURES


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**
            **DEFINITION**2006
                Form 10-K
            Progress
                Registrants’ annual report on Form 10-K for the fiscal year ended December
                31, 2006401(k)
            Progress
                Energy 401(k) Savings and Stock Ownership PlanAFUDC
            Allowance
                for funds used during constructionAHI
            Affordable
                housing investmentAOCI
            Accumulated
                other comprehensive income, a component of common stock
                equityARO
            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 TechnologyBcf
            Billion
                cubic feetBroad
                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
            Former
                Progress Ventures segment’s nonregulated 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
            Coal
                terminals and marketing operations that blend and transload coal
                as part
                of the transportation network for coal deliveryCoal
                Mining
            Five
                Progress Fuels subsidiaries engaged in the coal mining
                businessCoal
                and Synthetic Fuels
            Business
                segment 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
            Collectively,
                the Parent, PESC and consolidation entitiesCorporate
                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., LLC





4


DIG
                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 EnergyDSM
            Demand-side
                managementEarthco
            Four
                coal-based solid synthetic fuels limited liability companies of which
                three are wholly ownedECCR
            Energy
                Conservation Cost Recovery ClauseECRC
            Environmental
                Cost Recovery ClauseEIA
            Energy
                Information AgencyEIP
            Equity
                Incentive PlanEnergy
                Delivery
            Distribution
                operations of the UtilitiesEPA
            United
                States Environmental Protection AgencyEPACT
            Energy
                Policy Act of 2005ERO
            Electric
                reliability organizationESOP
            Employee
                Stock Ownership PlanFASB
            Financial
                Accounting Standards BoardFERC
            Federal
                Energy Regulatory CommissionFDCA
            Florida
                Department of Community AffairsFGT
            Florida
                Gas Transmission CompanyFIN
                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”Fitch
            Fitch
                RatingsFlorida
                Global Case
            U.S.
                Global, LLC v. Progress Energy, Inc. et alFlorida
                Progress
            Florida
                Progress CorporationFPSC
            Florida
                Public Service CommissionFRCC
            Florida
                Reliability Coordinating CouncilFSP
                FIN 39-1
            FASB
                Staff Position No. 39-1, “An Amendment of FIN 39, Offsetting of Amounts
                Related to Certain Contracts”Funding
                Corp.
            Florida
                Progress Funding Corporation, a wholly owned subsidiary of Florida
                ProgressGAAP
            Accounting
                principles generally accepted in the United States of
                AmericaGas
            Former
                Progress Ventures segment’s natural gas drilling and production
                businessthe
                Georgia Contracts
            Fixed
                price full-requirement contracts formerly serviced by
                CCOGeorgia
                Power
            Georgia
                Power Company, a subsidiary of Southern CompanyGeorgia
                Region
            Former
                reporting unit consisting of the Effingham, Monroe, Walton and Washington
                nonregulated generation plants in service and the Georgia
                ContractsGlobal
            U.S.
                Global, 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/s
            Kilowatt-hour/sLevel
                3
            Level
                3 Communications, Inc.LIBOR
            London
                Inter Bank Offering RateMD&A
            Management’s
                Discussion and Analysis of Financial Condition and Results of Operations
                contained in Part I, Item 2 of this Form
                10-Q





5


Medicare
                Act
            Medicare
                Prescription Drug, Improvement and Modernization Act of
                2003MGP
            Manufactured
                gas plantMW
            MegawattsMWh
            Megawatt-hoursMoody’s
            Moody’s
                Investors Service, Inc.NAAQS
            National
                Ambient Air Quality StandardsNCDWQ
            North
                Carolina Division of Water QualityNCNG
            North
                Carolina Natural Gas CorporationNCUC
            North
                Carolina Utilities CommissionNEIL
            Nuclear
                Electric Insurance LimitedNERC
            North
                American Electric Reliability CorporationNOL
            Net
                operating lossNOPR
            Notice
                of Proposed RulemakingNorth
                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 AgencyPRB
            Powder
                River BasinPreferred
                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 CorporationProgress
                Ventures
            Former
                business segment that primarily engaged in nonregulated energy generation,
                energy marketing activities and natural gas drilling and
                productionPRP
            Potentially
                responsible party, as defined in CERCLAPSSP
            Performance
                Share Sub-PlanPTC
            Progress
                Telecommunications Corporation





6


PT
                LLC
            Progress
                Telecom, LLCPUHCA
                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 agreementREPS
            North
                Carolina Renewable Energy and Efficiency Portfolio
                StandardReagents
            Commodities
                such as ammonia and limestone used in emissions control
                technologiesRockport
            Indiana
                Michigan Power Company’s Rockport Unit No. 2Robinson
            PEC’s
                Robinson Nuclear PlantROE
            Return
                on equityRowan
            Rowan
                County Power, LLCRSA
            Restricted
                stock awards programRTO
            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
                the
                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 and
                Hedging Activities”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”SNG
            Southern
                Natural Gas CompanySO2
            Sulfur
                dioxide





7


Subordinated
              Notes
            7.10%
              Junior Subordinated Defferable Interest Notes due 2039 issued by Funding
              Corp.Tax
                Agreement
            Intercompany
                Income Tax Allocation Agreementthe
                Threshold Price
            Price
                per barrel of unregulated domestic crude oil at which the value of
                Section
                29/45K tax credits begin to be reducedthe
                Trust
            FPC
                Capital Ithe
                Utilities
            Collectively,
                PEC and PEFWinchester
                Production
            Winchester
                Production Company, Ltd.Winter
                Park
            City
                of Winter Park, Fla.


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 facilities, 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; the financial
      resources and capital needed to comply with environmental laws and our ability
      to recover eligible costs under cost-recovery clauses or base rates; weather
      conditions that directly influence the production, delivery and 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; recurring seasonal fluctuations in demand for electricity; fluctuations
      in the price of energy commodities and purchased power and our ability to
      recover such costs through the regulatory process; economic fluctuations and
      the
      corresponding impact on our customers, including downturns in the housing and
      consumer credit markets; the ability of our subsidiaries to pay upstream
      dividends or distributions to the Parent; the impact on our facilities and
      businesses from a terrorist attack; the inherent risks associated with the
      operation of nuclear facilities, including environmental, health, regulatory
      and
      financial risks; 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 ability to successfully
      access capital markets on favorable terms; 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; the
      impact that increases in leverage may have on each of the Progress Registrants;
      the impact of derivative contracts used in the normal course of business; the
      investment performance of our pension and benefit plans; the Progress
      Registrants’ ability to control costs, including pension and benefit expense,
      and achieve our cost-management targets for 2007 and 2008; our ability to
      utilize tax credits from the production and sale of qualifying synthetic fuels
      under Internal Revenue Code Section 29/45K (Section 29/45K); the impact that
      future crude oil prices may have on our earnings from our coal-based solid
      synthetic fuels businesses; 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, 2006 (2006 Form 10-K), which was filed with
      the SEC on March 1, 2007, 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 it assess the
      effect of each such factor on the Progress Registrants.




9


**PART
      I.  FINANCIAL INFORMATION**


Item
      1.                      Financial
      Statements




**PROGRESS
      ENERGY, INC.**


**CONSOLIDATED
      INTERIM FINANCIAL STATEMENTS**


**September
      30, 2007**





**UNAUDITED
                CONSOLIDATED STATEMENTS of
                INCOME**Three
                Months Ended September 30,
            
            
            Nine
                Months Ended September 30,*(in
                millions, except per share data)*
            
            **2007**
            
            
            2006
            
            
            **2007**
            
            
            2006**Operating
                revenues**Electric
            
            **$**
            **2,741**
            
            
            $
            2,599
            
            
            **$**
            **6,934**
            
            
            $
            6,666Diversified
                business
            
            ****
            **359**
            
            
            
            177
            
            
            ****
            **906**
            
            
            
            631**Total
                operating revenues**
            
            ****
            **3,100**
            
            
            
            2,776
            
            
            ****
            **7,840**
            
            
            
            7,297**Operating
                expenses**UtilityFuel
                used in electric generation
            
            ****
            **929**
            
            
            
            860
            
            
            ****
            **2,381**
            
            
            
            2,259Purchased
                power
            
            ****
            **390**
            
            
            
            391
            
            
            ****
            **894**
            
            
            
            880Operation
                and maintenance
            
            ****
            **456**
            
            
            
            383
            
            
            ****
            **1,337**
            
            
            
            1,216Depreciation
                and amortization
            
            ****
            **221**
            
            
            
            243
            
            
            ****
            **662**
            
            
            
            705Taxes
                other than on income
            
            ****
            **135**
            
            
            
            141
            
            
            ****
            **384**
            
            
            
            380Other
            
            ****
            **−**
            
            
            
            −
            
            
            ****
            **14**
            
            
            
            (2
            )Diversified
                businessCost
                of sales
            
            ****
            **329**
            
            
            
            189
            
            
            ****
            **926**
            
            
            
            672Depreciation
                and amortization
            
            ****
            **2**
            
            
            
            2
            
            
            ****
            **6**
            
            
            
            21Impairment
                of long-lived assets
            
            ****
            **−**
            
            
            
            −
            
            
            ****
            **−**
            
            
            
            91Gain
                on the sales of assets
            
            ****
            **−**
            
            
            
            −
            
            
            ****
            **(17**
            **)**
            
            
            (4
            )Other
            
            ****
            **11**
            
            
            
            10
            
            
            ****
            **38**
            
            
            
            44**Total
                operating expenses**
            
            ****
            **2,473**
            
            
            
            2,219
            
            
            ****
            **6,625**
            
            
            
            6,262**Operating
                income**
            
            ****
            **627**
            
            
            
            557
            
            
            ****
            **1,215**
            
            
            
            1,035**Other
                income (expense)**Interest
                income
            
            ****
            **7**
            
            
            
            13
            
            
            ****
            **21**
            
            
            
            37Other,
                net
            
            ****
            **7**
            
            
            
            (9
            )
            
            ****
            **33**
            
            
            
            (1
            )**Total
                other income**
            
            ****
            **14**
            
            
            
            4
            
            
            ****
            **54**
            
            
            
            36**Interest
                charges**Net
                interest charges
            
            ****
            **159**
            
            
            
            148
            
            
            ****
            **444**
            
            
            
            473Allowance
                for borrowed funds used during construction
            
            ****
            **(5**
            **)**
            
            
            −
            
            
            ****
            **(12**
            **)**
            
            
            (4
            )**Total
                interest charges, net**
            
            ****
            **154**
            
            
            
            148
            
            
            ****
            **432**
            
            
            
            469**Income
                from continuing operations before income tax and minority
                interest**
            
            ****
            **487**
            
            
            
            413
            
            
            ****
            **837**
            
            
            
            602**Income
                tax expense**
            
            ****
            **154**
            
            
            
            133
            
            
            ****
            **175**
            
            
            
            205**Income
                from continuing operations before minority
                interest**
            
            ****
            **333**
            
            
            
            280
            
            
            ****
            **662**
            
            
            
            397**Minority
                interest in subsidiaries’ (income) loss, net of
                tax**
            
            ****
            **(14**
            **)**
            
            
            3
            
            
            ****
            **8**
            
            
            
            (10
            )**Income
                from continuing operations**
            
            ****
            **319**
            
            
            
            283
            
            
            ****
            **670**
            
            
            
            387**Discontinued
                operations, net of tax**
            
            ****
            **−**
            
            
            
            36
            
            
            ****
            **(269**
            **)**
            
            
            (70
            )**Net
                income**
            
            **$**
            **319**
            
            
            $
            319
            
            
            **$**
            **401**
            
            
            $
            317**Average
                common shares outstanding – basic**
            
            ****
            **257**
            
            
            
            251
            
            
            ****
            **256**
            
            
            
            250**Basic
                earnings per common share**Income
                from continuing operations
            
            **$**
            **1.24**
            
            
            $
            1.13
            
            
            **$**
            **2.62**
            
            
            $
            1.55Discontinued
                operations, net of tax
            
            
            −
            
            
            
            0.14
            
            
            ****
            **(1.05**
            **)**
            
            
            (0.28
            )Net
                income
            
            **$**
            **1.24**
            
            
            $
            1.27
            
            
            **$**
            **1.57**
            
            
            $
            1.27**Diluted
                earnings per common share**Income
                from continuing operations
            
            **$**
            **1.24**
            
            
            $
            1.13
            
            
            **$**
            **2.61**
            
            
            $
            1.54Discontinued
                operations, net of tax
            
            
            −
            
            
            
            0.14
            
            
            ****
            **(1.05**
            **)**
            
            
            (0.28
            )Net
                income
            
            **$**
            **1.24**
            
            
            $
            1.27
            
            
            **$**
            **1.56**
            
            
            $
            1.26**Dividends
                declared per common share**
            
            **$**
            **0.610**
            
            
            $
            0.605
            
            
            **$**
            **1.830**
            
            
            $
            1.815





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


10


PROGRESS
      ENERGY, INC.


**UNAUDITED
                CONSOLIDATED BALANCE
                SHEETS***(in
                millions)*
            
            **September
                30, 2007**
            
            
            December
                31, 2006**ASSETS****Utility
                plant**Utility
                plant in service
            
            **$**
            **24,624**
            
            
            $
            23,743Accumulated
                depreciation
            
            ****
            **(10,681**
            **)**
            
            
            (10,064
            )Utility
                plant in service, net
            
            ****
            **13,943**
            
            
            
            13,679Held
                for future use
            
            ****
            **10**
            
            
            
            10Construction
                work in progress
            
            ****
            **1,880**
            
            
            
            1,289Nuclear
                fuel, net of amortization
            
            ****
            **355**
            
            
            
            267**Total
                utility plant, net**
            
            ****
            **16,188**
            
            
            
            15,245**Current
                assets**Cash
                and cash equivalents
            
            ****
            **617**
            
            
            
            265Short-term
                investments
            
            ****
            **178**
            
            
            
            71Receivables,
                net
            
            ****
            **1,148**
            
            
            
            930Inventory
            
            ****
            **999**
            
            
            
            969Deferred
                fuel cost
            
            ****
            **177**
            
            
            
            196Deferred
                income taxes
            
            ****
            **50**
            
            
            
            159Assets
                of discontinued operations
            
            ****
            **28**
            
            
            
            887Derivative
                assets
            
            ****
            **185**
            
            
            
            1Prepayments
                and other current assets
            
            ****
            **162**
            
            
            
            107**Total
                current assets**
            
            ****
            **3,544**
            
            
            
            3,585**Deferred
                debits and other assets**Regulatory
                assets
            
            ****
            **1,113**
            
            
            
            1,231Nuclear
                decommissioning trust funds
            
            ****
            **1,358**
            
            
            
            1,287Diversified
                business property, net
            
            ****
            **41**
            
            
            
            31Miscellaneous
                other property and investments
            
            ****
            **441**
            
            
            
            456Goodwill
            
            ****
            **3,655**
            
            
            
            3,655Other
                assets and deferred debits
            
            ****
            **233**
            
            
            
            211**Total
                deferred debits and other assets**
            
            ****
            **6,841**
            
            
            
            6,871**Total
                assets**
            
            **$**
            **26,573**
            
            
            $
            25,701**CAPITALIZATION
                AND LIABILITIES****Common
                stock equity**Common
                stock without par value, 500 million shares authorized, 259 and 256
                million shares issued and outstanding, respectively
            
            **$**
            **5,996**
            
            
            $
            5,791Unearned
                ESOP shares (2 million shares)
            
            ****
            **(37**
            **)**
            
            
            (50
            )Accumulated
                other comprehensive loss
            
            ****
            **(54**
            **)**
            
            
            (49
            )Retained
                earnings
            
            ****
            **2,521**
            
            
            
            2,594**Total
                common stock equity**
            
            ****
            **8,426**
            
            
            
            8,286**Preferred
                stock of subsidiaries – not subject to mandatory
                redemption**
            
            ****
            **93**
            
            
            
            93**Minority
                interest**
            
            ****
            **64**
            
            
            
            10**Long-term
                debt, affiliate**
            
            ****
            **271**
            
            
            
            271**Long-term
                debt, net**
            
            ****
            **8,916**
            
            
            
            8,564**Total
                capitalization**
            
            ****
            **17,770**
            
            
            
            17,224**Current
                liabilities**Current
                portion of long-term debt
            
            ****
            **464**
            
            
            
            324Short-term
                debt
            
            ****
            **550**
            
            
            
            –Accounts
                payable
            
            ****
            **826**
            
            
            
            712Interest
                accrued
            
            ****
            **124**
            
            
            
            171Dividends
                declared
            
            ****
            **159**
            
            
            
            156Customer
                deposits
            
            ****
            **250**
            
            
            
            227Liabilities
                of discontinued operations
            
            ****
            **12**
            
            
            
            189Income
                taxes accrued
            
            ****
            **26**
            
            
            
            284Other
                current liabilities
            
            ****
            **806**
            
            
            
            755**Total
                current liabilities**
            
            ****
            **3,217**
            
            
            
            2,818**Deferred
                     credits and other liabilities**Noncurrent
                income tax liabilities
            
            ****
            **285**
            
            
            
            306Accumulated
                deferred investment tax credits
            
            ****
            **142**
            
            
            
            151Regulatory
                liabilities
            
            ****
            **2,385**
            
            
            
            2,543Asset
                retirement obligations
            
            ****
            **1,359**
            
            
            
            1,306Accrued
                pension and other benefits
            
            ****
            **896**
            
            
            
            957Other
                liabilities and deferred credits
            
            ****
            **519**
            
            
            
            396**Total
                deferred credits and other liabilities**
            
            ****
            **5,586**
            
            
            
            5,659**Commitments
                and contingencies (Notes 12 and 13)****Total
                capitalization and liabilities**
            
            **$**
            **26,573**
            
            
            $
            25,701


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




11


PROGRESS
      ENERGY, INC.


**UNAUDITED
                CONSOLIDATED STATEMENTS of CASH
                FLOWS***(in
                millions)*Nine
                Months Ended September 30
            
            **2007**
            
            
            2006**Operating
                activities**Net
                income
            
            **$**
            **401**
            
            
            $
            317Adjustments
                to reconcile net income to net cash provided by operating
                activitiesDiscontinued
                operations, net of tax
            
            ****
            **269**
            
            
            
            70Impairment
                of assets
            
            ****
            **−**
            
            
            
            91Depreciation
                and amortization
            
            ****
            **754**
            
            
            
            797Deferred
                income taxes
            
            ****
            **87**
            
            
            
            (52
            )Investment
                tax credits
            
            ****
            **(9**
            **)**
            
            
            (9
            )Deferred
                fuel cost
            
            ****
            **28**
            
            
            
            197Deferred
                income
            
            ****
            **(98**
            **)**
            
            
            (52
            )Other
                adjustments to net income
            
            ****
            **104**
            
            
            
            149Cash
                (used) provided by changes in operating assets and
                liabilitiesReceivables
            
            ****
            **(201**
            **)**
            
            
            (44
            )Inventory
            
            ****
            **(18**
            **)**
            
            
            (116
            )Prepayments
                and other current assets
            
            ****
            **(151**
            **)**
            
            
            (67
            )Accounts
                payable
            
            ****
            **112**
            
            
            
            33Income
                taxes, net
            
            ****
            **(342**
            **)**
            
            
            64Other
                current liabilities
            
            ****
            **89**
            
            
            
            93Other
                assets and deferred debits
            
            ****
            **(60**
            **)**
            
            
            35Other
                liabilities and deferred credits
            
            ****
            **(8**
            **)**
            
            
            3**Net
                cash provided by operating activities**
            
            ****
            **957**
            
            
            
            1,509**Investing
                activities**Gross
                utility property additions
            
            ****
            **(1,404**
            **)**
            
            
            (1,012
            )Diversified
                business property additions
            
            ****
            **(5**
            **)**
            
            
            (1
            )Nuclear
                fuel additions
            
            ****
            **(198**
            **)**
            
            
            (71
            )Proceeds
                from sales of discontinued operations and other assets, net of cash
                divested
            
            ****
            **659**
            
            
            
            548Purchases
                of available-for-sale securities and other investments
            
            ****
            **(1,072**
            **)**
            
            
            (1,687
            )Proceeds
                from sales of available-for-sale securities and other
                investments
            
            ****
            **939**
            
            
            
            1,611Other
                investing activities
            
            ****
            **16**
            
            
            
            (16
            )**Net
                cash used by investing activities**
            
            ****
            **(1,065**
            **)**
            
            
            (628
            )**Financing
                activities**Issuance
                of common stock
            
            ****
            **134**
            
            
            
            73Proceeds
                from issuance of long-term debt, net
            
            ****
            **742**
            
            
            
            397Net
                increase (decrease) in short-term debt
            
            ****
            **550**
            
            
            
            (175
            )Retirement
                of long-term debt
            
            ****
            **(287**
            **)**
            
            
            (848
            )Dividends
                paid on common stock
            
            ****
            **(469**
            **)**
            
            
            (454
            )Cash
                distributions to minority interests of consolidated
                subsidiary
            
            ****
            **(10**
            **)**
            
            
            (74
            )Other
                financing activities
            
            ****
            **22**
            
            
            
            (42
            )**Net
                cash provided (used) by financing activities**
            
            ****
            **682**
            
            
            
            (1,123
            )**Cash
                (used) provided by discontinued operations**Operating
                activities
            
            ****
            **(220**
            **)**
            
            
            115Investing
                activities
            
            ****
            **(2**
            **)**
            
            
            (143
            )**Net
                increase (decrease) in cash and cash equivalents**
            
            ****
            **352**
            
            
            
            (270
            )**Cash
                and cash equivalents at beginning of period**
            
            ****
            **265**
            
            
            
            605**Cash
                and cash equivalents at end of period**
            
            **$**
            **617**
            
            
            $
            335


12





**Supplemental
                disclosures**Significant
                non-cash transactionsCapital
                lease obligation incurred
            
            **$**
            **182**
            
            
            $
            –Note
                receivable for disposal of ownership interest in Ceredo
            
            **$**
            **48**
            
            
            $
            –Non-cash
                property additions accrued for as of September 30
            
            **$**
            **192**
            
            
            $
            145*See
                Notes to Progress Energy, Inc. Consolidated Interim Financial
                Statements.*


13


**CAROLINA
      POWER & LIGHT
      COMPANY**


**d/b/a
      PROGRESS ENERGY CAROLINAS, INC.**


**CONSOLIDATED
      INTERIM FINANCIAL STATEMENTS**


**September
      30, 2007**





**UNAUDITED
                CONSOLIDATED STATEMENTS of
                INCOME**Three
                Months Ended September 30,
            
            
            Nine
                Months Ended September 30,*(in
                millions)*
            
            **2007**
            
            
            2006
            
            
            **2007**
            
            
            2006**Operating
                revenues**Electric
            
            **$**
            **1,286**
            
            
            $
            1,200
            
            
            **$**
            **3,339**
            
            
            $
            3,113Diversified
                business
            
            ****
            **−**
            
            
            
            −
            
            
            ****
            **1**
            
            
            
            1**Total
                operating revenues**
            
            ****
            **1,286**
            
            
            
            1,200
            
            
            ****
            **3,340**
            
            
            
            3,114**Operating
                expenses**Fuel
                used in electric generation
            
            ****
            **385**
            
            
            
            322
            
            
            ****
            **1,041**
            
            
            
            880Purchased
                power
            
            ****
            **109**
            
            
            
            135
            
            
            ****
            **243**
            
            
            
            279Operation
                and maintenance
            
            ****
            **246**
            
            
            
            218
            
            
            ****
            **762**
            
            
            
            722Depreciation
                and amortization
            
            ****
            **118**
            
            
            
            128
            
            
            ****
            **353**
            
            
            
            383Taxes
                other than on income
            
            ****
            **52**
            
            
            
            51
            
            
            ****
            **151**
            
            
            
            141Other
            
            ****
            **1**
            
            
            
            −
            
            
            ****
            **−**
            
            
            
            −**Total
                operating expenses**
            
            ****
            **911**
            
            
            
            854
            
            
            ****
            **2,550**
            
            
            
            2,405**Operating
                income**
            
            ****
            **375**
            
            
            
            346
            
            
            ****
            **790**
            
            
            
            709**Other
                income (expense)**Interest
                income
            
            ****
            **5**
            
            
            
            7
            
            
            ****
            **16**
            
            
            
            18Other,
                net
            
            ****
            **(1**
            **)**
            
            
            (10
            )
            
            ****
            **9**
            
            
            
            (12
            )**Total
                other income (expense)**
            
            ****
            **4**
            
            
            
            (3
            )
            
            ****
            **25**
            
            
            
            6**Interest
                charges**Interest
                charges
            
            ****
            **58**
            
            
            
            44
            
            
            ****
            **169**
            
            
            
            158Allowance
                for borrowed funds used during construction
            
            ****
            **(2**
            **)**
            
            
            −
            
            
            ****
            **(4**
            **)**
            
            
            (1
            )**Total
                interest charges, net**
            
            ****
            **56**
            
            
            
            44
            
            
            ****
            **165**
            
            
            
            157**Income
                before income tax**
            
            ****
            **323**
            
            
            
            299
            
            
            ****
            **650**
            
            
            
            558**Income
                tax expense**
            
            ****
            **119**
            
            
            
            110
            
            
            ****
            **234**
            
            
            
            207**Net
                income**
            
            ****
            **204**
            
            
            
            189
            
            
            ****
            **416**
            
            
            
            351**Preferred
                stock dividend requirement**
            
            ****
            **1**
            
            
            
            1
            
            
            ****
            **2**
            
            
            
            2**Earnings
                for common stock**
            
            **$**
            **203**
            
            
            $
            188
            
            
            **$**
            **414**
            
            
            $
            349





*See
      Notes to PEC Consolidated Interim Financial Statements.*


14


CAROLINA
      POWER & LIGHT COMPANY


d/b/a
      PROGRESS ENERGY CAROLINAS, INC.


**UNAUDITED
                CONSOLIDATED BALANCE
                SHEETS***(in
                millions)*
            
            **September
                30, 2007**
            
            
            December
                31, 2006**ASSETS****Utility
                plant**Utility
                plant in service
            
            **$**
            **14,872**
            
            
            $
            14,356Accumulated
                depreciation
            
            ****
            **(6,905**
            **)**
            
            
            (6,408
            )Utility
                plant in service, net
            
            ****
            **7,967**
            
            
            
            7,948Held
                for future use
            
            ****
            **3**
            
            
            
            3Construction
                work in progress
            
            ****
            **615**
            
            
            
            617Nuclear
                fuel, net of amortization
            
            ****
            **277**
            
            
            
            209**Total
                utility plant, net**
            
            ****
            **8,862**
            
            
            
            8,777**Current
                assets**Cash
                and cash equivalents
            
            ****
            **89**
            
            
            
            71Short-term
                investments
            
            ****
            **–**
            
            
            
            50Receivables,
                net
            
            ****
            **533**
            
            
            
            473Receivables
                from affiliated companies
            
            ****
            **85**
            
            
            
            27Notes
                receivable from affiliated companies
            
            ****
            **–**
            
            
            
            24Inventory
            
            ****
            **505**
            
            
            
            497Deferred
                fuel cost
            
            ****
            **168**
            
            
            
            196Prepayments
                and other current assets
            
            ****
            **16**
            
            
            
            45**Total
                current assets**
            
            ****
            **1,396**
            
            
            
            1,383**Deferred
                debits and other assets**Regulatory
                assets
            
            ****
            **811**
            
            
            
            777Nuclear
                decommissioning trust funds
            
            ****
            **782**
            
            
            
            735Miscellaneous
                other property and investments
            
            ****
            **190**
            
            
            
            193Other
                assets and deferred debits
            
            ****
            **134**
            
            
            
            155**Total
                deferred debits and other assets**
            
            ****
            **1,917**
            
            
            
            1,860**Total
                assets**
            
            **$**
            **12,175**
            
            
            $
            12,020**CAPITALIZATION
                AND LIABILITIES****Common
                stock equity**Common
                stock without par value, 200 million shares authorized, 160 million
                shares
                issued and outstanding
            
            **$**
            **2,048**
            
            
            $
            2,010Unearned
                ESOP common stock
            
            ****
            **(37**
            **)**
            
            
            (50
            )Accumulated
                other comprehensive loss
            
            ****
            **(6**
            **)**
            
            
            (1
            )Retained
                earnings
            
            ****
            **1,726**
            
            
            
            1,431**Total
                common stock equity**
            
            ****
            **3,731**
            
            
            
            3,390**Preferred
                stock – not subject to mandatory redemption**
            
            ****
            **59**
            
            
            
            59**Long-term
                debt, net**
            
            ****
            **3,182**
            
            
            
            3,470**Total
                capitalization**
            
            ****
            **6,972**
            
            
            
            6,919**Current
                liabilities**Current
                portion of long-term debt
            
            ****
            **300**
            
            
            
            200Short-term
                debt
            
            ****
            **150**
            
            
            
            –Notes
                payable to affiliated companies
            
            ****
            **1**
            
            
            
            –Accounts
                payable
            
            ****
            **273**
            
            
            
            310Payables
                to affiliated companies
            
            ****
            **132**
            
            
            
            108Interest
                accrued
            
            ****
            **50**
            
            
            
            69Customer
                deposits
            
            ****
            **68**
            
            
            
            59Income
                taxes accrued
            
            ****
            **127**
            
            
            
            68Current
                portion of unearned revenue
            
            ****
            **18**
            
            
            
            71Other
                current liabilities
            
            ****
            **237**
            
            
            
            154**Total
                current liabilities**
            
            ****
            **1,356**
            
            
            
            1,039**Deferred
                credits and other liabilities**Noncurrent
                income tax liabilities
            
            ****
            **914**
            
            
            
            909Accumulated
                deferred investment tax credits
            
            ****
            **123**
            
            
            
            128Regulatory
                liabilities
            
            ****
            **1,098**
            
            
            
            1,320Asset
                retirement obligations
            
            ****
            **1,048**
            
            
            
            1,004Accrued
                pension and other benefits
            
            ****
            **555**
            
            
            
            581Other
                liabilities and deferred credits
            
            ****
            **109**
            
            
            
            120**Total
                deferred credits and other liabilities**
            
            ****
            **3,847**
            
            
            
            4,062**Commitments
                and contingencies (Notes 12 and 13)****Total
                capitalization and liabilities**
            
            **$**
            **12,175**
            
            
            $
            12,020





*See
      Notes to PEC Consolidated Interim Financial Statements.*


15


CAROLINA
      POWER & LIGHT COMPANY


d/b/a
      PROGRESS ENERGY CAROLINAS, INC.


**UNAUDITED
                CONSOLIDATED STATEMENTS of CASH
                FLOWS***(in
                millions)*Nine
                Months Ended September 30
            
            **2007**
            
            
            2006**Operating
                activities**Net
                income
            
            **$**
            **416**
            
            
            $
            351Adjustments
                to reconcile net income to net cash provided by operating
                activitiesDepreciation
                and amortization
            
            ****
            **419**
            
            
            
            446Deferred
                income taxes and investment tax credits, net
            
            ****
            **62**
            
            
            
            23Deferred
                fuel cost (credit)
            
            ****
            **7**
            
            
            
            (47
            )Other
                adjustments to net income
            
            ****
            **(37**
            **)**
            
            
            32Cash
                (used) provided by changes in operating assets and
                liabilitiesReceivables
            
            ****
            **(62**
            **)**
            
            
            24Receivables
                from affiliated companies
            
            ****
            **(34**
            **)**
            
            
            22Inventory
            
            ****
            **(2**
            **)**
            
            
            (23
            )Prepayments
                and other current assets
            
            ****
            **(2**
            **)**
            
            
            6Accounts
                payable
            
            ****
            **16**
            
            
            
            21Payables
                to affiliated companies
            
            ****
            **23**
            
            
            
            (8
            )Income
                taxes, net
            
            ****
            **64**
            
            
            
            (26
            )Other
                current liabilities
            
            ****
            **13**
            
            
            
            21Other
                assets and deferred debits
            
            ****
            **(19**
            **)**
            
            
            24Other
                liabilities and deferred credits
            
            ****
            **11**
            
            
            
            2**Net
                cash provided by operating activities**
            
            ****
            **875**
            
            
            
            868**Investing
                activities**Gross
                utility property additions
            
            ****
            **(587**
            **)**
            
            
            (493
            )Nuclear
                fuel additions
            
            ****
            **(159**
            **)**
            
            
            (65
            )Purchases
                of available-for-sale securities and other investments
            
            ****
            **(472**
            **)**
            
            
            (736
            )Proceeds
                from sales of available-for-sale securities and other
                investments
            
            ****
            **498**
            
            
            
            772Changes
                in advances to affiliates
            
            ****
            **1**
            
            
            
            –Other
                investing activities
            
            ****
            **2**
            
            
            
            (3
            )**Net
                cash used by investing activities**
            
            ****
            **(717**
            **)**
            
            
            (525
            )**Financing
                activities**Net
                increase (decrease) in short-term debt
            
            ****
            **150**
            
            
            
            (73
            )Retirement
                of long-term debt
            
            ****
            **(200**
            **)**
            
            
            –Changes
                in advances from affiliates
            
            ****
            **–**
            
            
            
            (9
            )Dividends
                paid to parent
            
            ****
            **(108**
            **)**
            
            
            (255
            )Dividends
                paid on preferred stock
            
            ****
            **(2**
            **)**
            
            
            (2
            )Other
                financing activities
            
            ****
            **20**
            
            
            
            1**Net
                cash used by financing activities**
            
            ****
            **(140**
            **)**
            
            
            (338
            )**Net
                increase in cash and cash equivalents**
            
            ****
            **18**
            
            
            
            5**Cash
                and cash equivalents at beginning of period**
            
            ****
            **71**
            
            
            
            125**Cash
                and cash equivalents at end of period**
            
            **$**
            **89**
            
            
            $
            130**Supplemental
                disclosures**Significant
                non-cash transactionsNon-cash
                property additions accrued for as of September 30
            
            **$**
            **67**
            
            
            $
            88*See
                Notes to PEC Consolidated Interim Financial
                Statements.*





16


**FLORIDA
      POWER CORPORATION**


**d/b/a
      PROGRESS ENERGY FLORIDA, INC.**


**INTERIM
      FINANCIAL STATEMENTS**


**September
      30, 2007**





**UNAUDITED
                STATEMENTS of
                INCOME**Three
                Months Ended September 30,
            
            
            Nine
                Months Ended September 30,*(in
                millions)*
            
            **2007**
            
            
            2006
            
            
            **2007**
            
            
            2006**Operating
                revenues**
            
            **$**
            **1,456**
            
            
            $
            1,399
            
            
            **$**
            **3,596**
            
            
            $
            3,553**Operating
                expenses**Fuel
                used in electric generation
            
            ****
            **544**
            
            
            
            538
            
            
            ****
            **1,340**
            
            
            
            1,379Purchased
                power
            
            ****
            **281**
            
            
            
            256
            
            
            ****
            **651**
            
            
            
            601Operation
                and maintenance
            
            ****
            **213**
            
            
            
            171
            
            
            ****
            **586**
            
            
            
            515Depreciation
                and amortization
            
            ****
            **100**
            
            
            
            108
            
            
            ****
            **297**
            
            
            
            301Taxes
                other than on income
            
            ****
            **83**
            
            
            
            89
            
            
            ****
            **233**
            
            
            
            238Other
            
            ****
            **−**
            
            
            
            −
            
            
            ****
            **12**
            
            
            
            (2
            )**Total
                operating expenses**
            
            ****
            **1,221**
            
            
            
            1,162
            
            
            ****
            **3,119**
            
            
            
            3,032**Operating
                income**
            
            ****
            **235**
            
            
            
            237
            
            
            ****
            **477**
            
            
            
            521**Other
                income**Interest
                income
            
            ****
            **1**
            
            
            
            4
            
            
            ****
            **3**
            
            
            
            12Other,
                net
            
            ****
            **12**
            
            
            
            6
            
            
            ****
            **27**
            
            
            
            8**Total
                other income**
            
            ****
            **13**
            
            
            
            10
            
            
            ****
            **30**
            
            
            
            20**Interest
                charges**Interest
                charges
            
            ****
            **45**
            
            
            
            39
            
            
            ****
            **126**
            
            
            
            119Allowance
                for borrowed funds used during construction
            
            ****
            **(3**
            **)**
            
            
            −
            
            
            ****
            **(8**
            **)**
            
            
            (3
            )**Total
                interest charges, net**
            
            ****
            **42**
            
            
            
            39
            
            
            ****
            **118**
            
            
            
            116**Income
                before income tax**
            
            ****
            **206**
            
            
            
            208
            
            
            ****
            **389**
            
            
            
            425**Income
                tax expense**
            
            ****
            **68**
            
            
            
            83
            
            
            ****
            **122**
            
            
            
            160**Net
                income**
            
            ****
            **138**
            
            
            
            125
            
            
            ****
            **267**
            
            
            
            265**Preferred
                stock dividend requirement**
            
            ****
            **−**
            
            
            
            −
            
            
            ****
            **1**
            
            
            
            1**Earnings
                for common stock**
            
            **$**
            **138**
            
            
            $
            125
            
            
            **$**
            **266**
            
            
            $
            264





*See
      Notes to PEF Interim Financial Statements.*


17


FLORIDA
      POWER CORPORATION


d/b/a
      PROGRESS ENERGY FLORIDA, INC.


**UNAUDITED
                BALANCE SHEETS***(in
                millions)*
            
            **September
                30, 2007**
            
            
            December
                31, 2006**ASSETS****Utility
                plant**Utility
                plant in service
            
            **$**
            **9,567**
            
            
            $
            9,202Accumulated
                depreciation
            
            ****
            **(3,719**
            **)**
            
            
            (3,602
            )Utility
                plant in service, net
            
            ****
            **5,848**
            
            
            
            5,600Held
                for future use
            
            ****
            **7**
            
            
            
            7Construction
                work in progress
            
            ****
            **1,265**
            
            
            
            672Nuclear
                fuel, net of amortization
            
            ****
            **78**
            
            
            
            58**Total
                utility plant, net**
            
            ****
            **7,198**
            
            
            
            6,337**Current
                assets**Cash
                and cash equivalents
            
            ****
            **325**
            
            
            
            23Short-term
                investments
            
            ****
            **178**
            
            
            
            −Receivables,
                net
            
            ****
            **443**
            
            
            
            340Receivables
                from affiliated companies
            
            ****
            **13**
            
            
            
            11Deferred
                income taxes
            
            ****
            **73**
            
            
            
            86Inventory
            
            ****
            **466**
            
            
            
            436Income
                taxes receivable
            
            ****
            **−**
            
            
            
            47Prepayments
                and other current assets
            
            ****
            **33**
            
            
            
            62**Total
                current assets**
            
            ****
            **1,531**
            
            
            
            1,005**Deferred
                debits and other assets**Regulatory
                assets
            
            ****
            **302**
            
            
            
            454Nuclear
                decommissioning trust funds
            
            ****
            **576**
            
            
            
            552Miscellaneous
                other property and investments
            
            ****
            **46**
            
            
            
            45Prepaid
                pension cost
            
            ****
            **192**
            
            
            
            174Other
                assets and deferred debits
            
            ****
            **51**
            
            
            
            26**Total
                deferred debits and other assets**
            
            ****
            **1,167**
            
            
            
            1,251**Total
                assets**
            
            **$**
            **9,896**
            
            
            $
            8,593**CAPITALIZATION
                AND LIABILITIES****Common
                stock equity**Common
                stock without par value, 60 million shares authorized, 100 shares
                issued
                and outstanding
            
            **$**
            **1,107**
            
            
            $
            1,100Accumulated
                other comprehensive loss
            
            ****
            **(9**
            **)**
            
            
            (1
            )Retained
                earnings
            
            ****
            **1,851**
            
            
            
            1,588**Total
                common stock equity**
            
            ****
            **2,949**
            
            
            
            2,687**Preferred
                stock – not subject to mandatory redemption**
            
            ****
            **34**
            
            
            
            34**Long-term
                debt, net**
            
            ****
            **3,137**
            
            
            
            2,468**Total
                capitalization**
            
            ****
            **6,120**
            
            
            
            5,189**Current
                liabilities**Current
                portion of long-term debt
            
            ****
            **84**
            
            
            
            89Notes
                payable to affiliated companies
            
            ****
            **−**
            
            
            
            47Accounts
                payable
            
            ****
            **485**
            
            
            
            292Payables
                to affiliated companies
            
            ****
            **72**
            
            
            
            116Interest
                accrued
            
            ****
            **28**
            
            
            
            38Customer
                deposits
            
            ****
            **182**
            
            
            
            168Derivative
                liabilities
            
            ****
            **31**
            
            
            
            89Current
                regulatory liabilities
            
            ****
            **123**
            
            
            
            76Other
                current liabilities
            
            ****
            **210**
            
            
            
            89**Total
                current liabilities**
            
            ****
            **1,215**
            
            
            
            1,004**Deferred
                credits and other liabilities**Noncurrent
                income tax liabilities
            
            ****
            **420**
            
            
            
            466Accumulated
                deferred investment tax credits
            
            ****
            **19**
            
            
            
            23Regulatory
                liabilities
            
            ****
            **1,160**
            
            
            
            1,091Asset
                retirement obligations
            
            ****
            **311**
            
            
            
            299Accrued
                pension and other benefits
            
            ****
            **319**
            
            
            
            332Other
                liabilities and deferred credits
            
            ****
            **332**
            
            
            
            189**Total
                deferred credits and other liabilities**
            
            ****
            **2,561**
            
            
            
            2,400**Commitments
                and contingencies (Notes 12 and 13)****Total
                capitalization and liabilities**
            
            **$**
            **9,896**
            
            
            $
            8,593





*See
      Notes to PEF Interim Financial Statements.*


18


FLORIDA
      POWER CORPORATION


d/b/a
      PROGRESS ENERGY FLORIDA, INC.


**UNAUDITED
                STATEMENTS of CASH
                FLOWS***(in
                millions)*Nine
                Months Ended September 30
            
            **2007**
            
            
            2006**Operating
                activities**Net
                income
            
            **$**
            **267**
            
            
            $
            265Adjustments
                to reconcile net income to net cash provided by operating
                activitiesDepreciation
                and amortization
            
            ****
            **313**
            
            
            
            323Deferred
                income taxes and investment tax credits, net
            
            ****
            **(50**
            **)**
            
            
            (46
            )Deferred
                fuel cost
            
            ****
            **21**
            
            
            
            244Other
                adjustments to net income
            
            ****
            **27**
            
            
            
            9Cash
                (used) provided by changes in operating assets and
                liabilitiesReceivables
            
            ****
            **(110**
            **)**
            
            
            (100
            )Receivables
                from affiliated companies
            
            ****
            **(2**
            **)**
            
            
            6Inventory
            
            ****
            **(22**
            **)**
            
            
            (117
            )Prepayments
                and other current assets
            
            ****
            **56**
            
            
            
            (44
            )Accounts
                payable
            
            ****
            **137**
            
            
            
            43Payables
                to affiliated companies
            
            ****
            **(46**
            **)**
            
            
            (13
            )Income
                taxes, net
            
            ****
            **98**
            
            
            
            14Other
                current liabilities
            
            ****
            **69**
            
            
            
            94Other
                assets and deferred debits
            
            ****
            **(25**
            **)**
            
            
            4Other
                liabilities and deferred credits
            
            ****
            **(6**
            **)**
            
            
            (28
            )**Net
                cash provided by operating activities**
            
            ****
            **727**
            
            
            
            654**Investing
                activities**Gross
                utility property additions
            
            ****
            **(819**
            **)**
            
            
            (528
            )Nuclear
                fuel additions
            
            ****
            **(39**
            **)**
            
            
            (6
            )Purchases
                of available-for-sale securities and other investments
            
            ****
            **(457**
            **)**
            
            
            (547
            )Proceeds
                from sales of available-for-sale securities and other
                investments
            
            ****
            **279**
            
            
            
            547Other
                investing activities
            
            ****
            **–**
            
            
            
            4**Net
                cash used by investing activities**
            
            ****
            **(1,036**
            **)**
            
            
            (530
            )**Financing
                activities**Proceeds
                from issuance of long-term debt, net
            
            ****
            **742**
            
            
            
            –Net
                decrease in short-term debt
            
            ****
            **–**
            
            
            
            (102
            )Retirement
                of long-term debt
            
            ****
            **(87**
            **)**
            
            
            (47
            )Changes
                in advances from affiliates
            
            ****
            **(45**
            **)**
            
            
            –Dividends
                paid to parent
            
            ****
            **–**
            
            
            
            (176
            )Dividends
                paid on preferred stock
            
            ****
            **(1**
            **)**
            
            
            (1
            )Other
                financing activities
            
            ****
            **2**
            
            
            
            –**Net
                cash provided (used) by financing activities**
            
            ****
            **611**
            
            
            
            (326
            )**Net
                increase (decrease) in cash and cash equivalents**
            
            ****
            **302**
            
            
            
            (202
            )**Cash
                and cash equivalents at beginning of period**
            
            ****
            **23**
            
            
            
            218**Cash
                and cash equivalents at end of period**
            
            **$**
            **325**
            
            
            $
            16**Supplemental
                disclosures**Significant
                non-cash transactionsCapital
                lease obligation incurred
            
            **$**
            **182**
            
            
            $
            –Non-cash
                property additions accrued for as of September 30
            
            **$**
            **125**
            
            
            $
            48*See
                Notes to PEF Interim Financial Statements.*





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 INTERIM FINANCIAL
      STATEMENTS**





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





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




**Registrant**
            **Applicable
                Notes**PEC
            1,
                2, 4 through 9, and 11 through 13PEF
            1,
                2, 4 through 9, and 11 through
                13


20


PROGRESS
      ENERGY, INC.


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


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


**COMBINED
      NOTES TO UNAUDITED INTERIM FINANCIAL STATEMENTS**





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**




The
      Parent is a holding company headquartered in Raleigh, N.C., and is subject
      to
      regulation by the Federal Energy Regulatory Commission (FERC) under the
      regulatory jurisdiction of the Public Utility Holding Company Act of 2005 (PUHCA
      2005).




Our
      reportable operating segments are: PEC, PEF and Coal and Synthetic Fuels. Our
      PEC and PEF segments are primarily engaged in the generation, transmission,
      distribution and sale of electricity. Our Coal and Synthetic Fuels segment
      is
      primarily engaged in the production and sale of coal-based solid synthetic
      fuels
      as defined under the Internal Revenue Code (the Code), the operation of
      synthetic fuels facilities for third parties, and coal terminal services. On
      September 14, 2007, we idled production of synthetic fuels at our majority-owned
      synthetic fuels facilities due to the current high level of oil prices. On
      October 12, 2007, based upon the continued high level of oil prices, unfavorable
      oil price projections through the end of 2007, and the expiration of the current
      synthetic fuels tax credit program at the end of 2007, we decided to permanently
      cease production of synthetic fuels at our majority-owned facilities. Our
      Corporate and Other segment (Corporate and Other) is comprised of the activities
      of the Parent and Progress Energy Service Company (PESC) as well as nonregulated
      businesses, which do not separately meet the disclosure requirements as a
      business segment.




PEC
      and
      PEF are regulated public utilities. PEC’s service territory covers portions of
      North Carolina and South Carolina and PEF’s covers portions of Florida. PEC’s
      subsidiaries are involved in insignificant nonregulated business activities.
      PEC
      is subject to the regulatory provisions of the North Carolina Utilities
      Commission (NCUC) and the Public Service Commission of South Carolina (SCPSC);
      PEF is subject to the regulatory provisions of the Florida Public Service
      Commission (FPSC). Both of the Utilities are also subject to regulation by
      the
      United States Nuclear Regulatory Commission (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, 2006 condensed balance
      sheet data was derived from audited financial statements but does not include
      all disclosures required by GAAP. Because the accompanying interim financial
      statements do not include all of the information and footnotes required by
      GAAP
      for annual financial statements, they should be read in conjunction with the
      audited financial statements and notes thereto included in the Progress
      Registrants’ annual report on Form 10-K for the fiscal year ended December 31,
      2006 (2006 Form 10-K).




In
      accordance with the provisions of Accounting Principles Board Opinion No. 28,
      “Interim Financial Reporting,” GAAP requires companies to apply a levelized
      effective tax rate to interim periods that is consistent with the estimated
      annual effective tax rate. The intra-period tax allocation, 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 interim periods are primarily due to the recognition of synthetic
      fuels
      tax credits and




21


seasonal
      fluctuations in energy sales and earnings from the Utilities. Income tax expense
      was increased (decreased) for the Progress Registrants for the three and nine
      months ended September 30, 2007 and 2006, as follows:




Three
                Months Ended September 30,
            
            
            Nine
                Months Ended September 30,*(in
                millions)*
            
            **2007**
            
            
            2006
            
            
            **2007**
            
            
            2006Progress
                Energy
            
            **$**
            **(26**
            **)**
            
            $
            (12
            )
            
            **$**
            **(3**
            **)**
            
            $
            7PEC
            
            ****
            **(1**
            **)**
            
            
            1
            
            
            ****
            **(2**
            **)**
            
            
            –PEF
            
            ****
            **(4**
            **)**
            
            
            2
            
            
            ****
            **(3**
            **)**
            
            
            2





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




Three
                Months Ended September 30,
            
            
            Nine
                Months Ended September 30,*(in
                millions)*
            
            **2007**
            
            
            2006
            
            
            **2007**
            
            
            2006Progress
                Energy
            
            **$**
            **92**
            
            
            $
            89
            
            
            **$**
            **229**
            
            
            $
            223PEC
            
            ****
            **30**
            
            
            
            28
            
            
            ****
            **78**
            
            
            
            71PEF
            
            ****
            **62**
            
            
            
            61
            
            
            ****
            **151**
            
            
            
            152





The
      amounts included in these financial statements are unaudited but, in the opinion
      of management, reflect all adjustments necessary to fairly present the Progress
      Registrants’ financial position and results of operations for the interim
      periods. Unless otherwise noted, all adjustments are normal and recurring in
      nature. Due to seasonal weather variations 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 2006 have been reclassified to conform to the 2007
      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 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.
      At
      September 30, 2007, the total assets of Ceredo were $69 million and consisted
      primarily of derivative assets. See Note 3I 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 investments
      in five limited liability partnerships and limited liability corporations.
      At
      September 30, 2007, the aggregate additional maximum loss exposure that we
      could
      be required to record in our income statement as a result




22


of
      these
      arrangements was $6 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, 2007, 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 investments in 20 limited
      liability partnerships, limited liability corporations and venture capital
      funds
      and two building leases with special-purpose entities. At September 30, 2007,
      the aggregate maximum loss exposure that PEC could be required to record on
      its
      income statement as a result of these arrangements totals approximately $19
      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.
      See Note 1 in the 2006 Form 10-K for additional information.




***PEF***




PEF
      has
      interests in three variable interest entities for which PEF is not the primary
      beneficiary. These arrangements include investments in one operating lease,
      one
      venture capital fund and one building lease with a special-purpose entity.
      At
      September 30, 2007, the aggregate maximum loss exposure that PEF could be
      required to record in its income statement as a result of these arrangements
      was
      $56 million. The majority of this exposure is related to a prepayment clause
      in
      the building lease and is not considered equity at risk. 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 STANDARD**




Refer
      to
      Note 7 for information regarding our first quarter 2007 implementation of FASB
      Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (FIN
      48).




*SFAS
      No. 157, “Fair Value Measurements”*




In
      September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (SFAS
      No. 157), which redefines 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.” SFAS No. 157 establishes a fair
      value hierarchy that categorizes and prioritizes the inputs that should be
      used
      to estimate fair value. We will implement SFAS No. 157 as of January 1, 2008.
      We
      do not expect the adoption of SFAS No. 157 to have a material impact on our
      or
      the Utilities' financial position or results of operations.




*SFAS
      No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities –
Including an amendment of FASB Statement No. 115”*




In
      February 2007, the FASB issued Statement of Financial Accounting Standards
      (SFAS) No. 159, "The Fair Value Option for Financial Assets and Financial
      Liabilities – Including an amendment of FASB Statement No. 115"




23


(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 is effective as of the beginning of an entity's first fiscal year
      that begins after November 15, 2007, which for us is January 1, 2008. We are
      currently evaluating the impact of the adoption of SFAS No. 159, but we do
      not
      expect it to have a material impact on our or the Utilities' financial position
      or results of operations.




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




FASB
      Interpretation No. 39, “Offsetting of Amounts Related to Certain Contracts” (FIN
      39), specifies what conditions must be met for an entity to have the right
      to
      offset assets and liabilities in the balance sheet and clarifies when it is
      appropriate to offset amounts recognized for forward, interest rate swap,
      currency swap, option, and other conditional or exchange contracts. FIN 39
      also
      permits offsetting of fair value amounts recognized for multiple contracts
      executed with the same counterparty under a master netting arrangement. On
      April
      30, 2007, the FASB issued Staff Position FIN 39-1 (FSP FIN 39-1) which amends
      portions of FIN 39 to make certain terms consistent with those used in SFAS
      No.
      133. FSP FIN 39-1 also amends FIN 39 to allow for the offsetting of fair value
      amounts for the right to reclaim collateral assets or liabilities arising from
      the same master netting arrangement as the derivative instruments. We will
      implement the FSP as of January 1, 2008, as a retrospective change in accounting
      principle for all financial statements presented. We and the Utilities currently
      offset fair value amounts recognized for derivative instruments under master
      netting arrangements. Upon adoption of FSP FIN 39-1, we and the Utilities expect
      to change our accounting policy to not offset fair value amounts for such
      derivatives and related collateral. We expect this change in policy to result
      in
      increases to current and non-current assets, total assets, current and
      non-current liabilities, and total liabilities, but will have no impact on
      our
      or the Utilities’ results of operations or equity.




**3.**
            **DIVESTITURES**




**A.           CCO
      – Georgia Region**




On
      March
      9, 2007, our subsidiary, Progress 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 quarter
      ended March 31, 2007, we reversed $16 million after-tax of the impairment
      recorded in 2006. During each of the quarters ended June 30, 2007, and September
      30, 2007, we reversed an additional $1 million after-tax of the impairment
      as a
      result of post-closing adjustments.




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




The
      accompanying consolidated financial statements have been restated for all
      periods presented to 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 and 2006, was $11 million and $28 million, respectively.
      Pre-tax interest expense allocated for the three months ended September 30,
      2006, was $9 million. We ceased recording depreciation upon classification
      of
      the assets as discontinued operations in December 2006. After-tax depreciation
      expense during the three and nine months ended September 30, 2006, was $4
      million and $11




24


million,
      respectively. 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)*
            
            **2007**
            
            
            2006
            
            
            **2007**
            
            
            2006Revenues
            
            **$**
            **1**
            
            
            $
            141
            
            
            **$**
            **407**
            
            
            $
            485Loss
                before income taxes
            
            ****
            **(1**
            **)**
            
            
            (65
            )
            
            ****
            **(444**
            **)**
            
            
            (183
            )Income
                tax benefit
            
            ****
            **–**
            
            
            
            25
            
            
            ****
            **164**
            
            
            
            69Net
                loss from discontinued operations
            
            ****
            **(1**
            **)**
            
            
            (40
            )
            
            ****
            **(280**
            **)**
            
            
            (114
            )Reversal
                of estimated loss on disposal of discontinued operations, including
                income
                tax benefit of $1and $8, respectively
            
            ****
            **1**
            
            
            
            –
            
            
            ****
            **18**
            
            
            
            –Loss
                from discontinued operations
            
            **$**
            **–**
            
            
            $
            (40
            )
            
            **$**
            **(262**
            **)**
            
            $
            (114
            )





**B.           Natural
      Gas Drilling and Production**




On
      October 2, 2006, we sold our natural gas drilling and production business (Gas)
      to EXCO Resources, Inc. for approximately $1.1 billion in net proceeds. Gas
      included Winchester Production Company, Ltd. (Winchester Production),
      Westchester Gas Company, Texas Gas Gathering and Talco Midstream Assets Ltd.;
      all were subsidiaries of Progress Fuels. We used the proceeds from the sale
      primarily to reduce holding company debt and for other corporate
      purposes.




Based
      on
      the net proceeds associated with the sale, we recorded an after-tax net gain
      on
      disposal of $300 million during the year ended December 31, 2006. We recorded
      an
      after-tax loss of $1 million during the three months ended March 31, 2007,
      primarily related to working capital adjustments.




The
      accompanying consolidated financial statements have been restated for all
      periods presented to reflect all the operations of Gas as discontinued
      operations. Interest expense has been allocated to discontinued operations
      based
      on their respective net assets, assuming a uniform debt-to-equity ratio across
      our operations. Pre-tax interest expense allocated for the three and nine months
      ended September 30, 2006, was $4 million and $13 million, respectively. We
      ceased recording depreciation upon classification of the assets as discontinued
      operations in July 2006. After-tax depreciation expense during the nine months
      ended September 30, 2006, was $16 million. Results of Gas 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)*
            
            **2007**
            
            
            2006
            
            
            **2007**
            
            
            2006Revenues
            
            **$**
            **–**
            
            
            $
            100
            
            
            **$**
            **–**
            
            
            $
            192Earnings
                before income taxes
            
            ****
            **–**
            
            
            
            88
            
            
            ****
            **–**
            
            
            
            138Income
                tax benefit (expense)
            
            ****
            **1**
            
            
            
            (31
            )
            
            ****
            **1**
            
            
            
            (54
            )Net
                earnings from discontinued operations
            
            ****
            **1**
            
            
            
            57
            
            
            ****
            **1**
            
            
            
            84Loss
                on disposal of discontinued operations, including income tax benefit
                of
                $1
            
            
            –
            
            
            
            –
            
            
            ****
            **(1**
            **)**
            
            
            –Earnings
                from discontinued operations
            
            **$**
            **1**
            
            
            $
            57
            
            
            **$**
            **–**
            
            
            $
            84





**C.           CCO
      – DeSoto and Rowan Generation Facilities**




On
      May 2,
      2006, our board of directors approved a plan to divest of two subsidiaries
      of
      PVI, DeSoto County Generating Co., LLC (DeSoto) and Rowan County Power, LLC
      (Rowan). DeSoto owns a 320 MW dual-fuel combustion turbine electric generation
      facility in DeSoto County, Fla., and Rowan owns a 925 MW dual-fuel combined
      cycle and combustion turbine electric generation facility in Rowan County,
      N.C.
      On May 8, 2006, we entered into definitive agreements to sell DeSoto and Rowan,
      including certain existing power supply contracts, to Southern Power Company,
      a
      subsidiary of Southern Company, for gross sales prices of approximately $80
      million




25


and
      $325
      million, respectively. We used the proceeds from the sales to reduce debt and
      for other corporate purposes.




The
      sale
      of DeSoto closed in the second quarter of 2006 and the sale of Rowan closed
      during the third quarter of 2006. Based on the gross proceeds associated with
      the sales, we recorded an after-tax loss on disposal of $65 million during
      the
      nine months ended September 30, 2006.




The
      accompanying consolidated financial statements have been restated for all
      periods presented to reflect the operations of DeSoto and Rowan 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, 2006, was $6 million. We ceased recording depreciation upon
      classification of the assets as discontinued operations in May 2006. After-tax
      depreciation expense during the nine months ended September 30, 2006, was $3
      million. Results of DeSoto and Rowan discontinued operations for the three
      and
      nine months ended September 30 were as follows:




*(in
                millions*
            
            Three
                Months Ended September 30, 2006
            
            
            Nine
                Months Ended September 30, 2006Revenues
            
            $
            50
            
            
            $
            64Earnings
                before income taxes
            
            
            30
            
            
            
            15Income
                tax expense
            
            
            (12
            )
            
            
            (6
            )Net
                earnings from discontinued operations
            
            
            18
            
            
            
            9Loss
                on disposal of discontinued operations, including income tax benefit
                of $5
                and $40, respectively
            
            
            (6
            )
            
            
            (65
            )Earnings
                (loss) from discontinued operations
            
            $
            12
            
            
            $
            (56
            )





**D.           Progress
      Telecom, LLC**




On
      March
      20, 2006, we completed the sale of Progress Telecom, LLC (PT LLC) to Level
      3
      Communications, Inc. (Level 3). We received gross proceeds comprised of cash
      of
      $69 million and approximately 20 million shares of Level 3 common stock valued
      at an estimated $66 million on the date of the sale. Our net proceeds from
      the
      sale of approximately $70 million, after consideration of minority interest,
      were used to reduce debt. Prior to the sale, we had a 51 percent interest in
      PT
      LLC. See Note 11 for a discussion of the subsequent sale of the Level 3
      stock.




Based
      on
      the net proceeds associated with the sale and after consideration of minority
      interest, we recorded an after-tax net gain on disposal of $24 million during
      the three months ended March 31, 2006. During the three months ended June 30,
      2006, we recorded an additional after-tax gain of $5 million in connection
      with
      certain tax matters. During the three months ended September 30, 2006, we
      recorded a $1 million adjustment related to additional tax expenses resulting
      in
      a total after-tax gain of $28 million for the nine months ended September 30,
      2006.




The
      accompanying consolidated financial statements have been restated for all
      periods presented to reflect the operations of PT LLC as discontinued
      operations. We ceased recording depreciation upon classification of the assets
      as discontinued operations in January 2006. After-tax depreciation expense
      during the nine months ended September 30, 2006, was $1 million. Results of
      PT
      LLC discontinued operations for the three and nine months ended September 30
      were as follows:




26







*(in
                millions)*
            
            Three
                Months Ended September 30, 2006
            
            
            Nine
                Months Ended September 30, 2006Revenues
            
            $
            –
            
            
            $
            18Earnings
                before income taxes
            
            
            2
            
            
            
            5Income
                tax expense
            
            
            –
            
            
            
            (4
            )Minority
                interest
            
            
            –
            
            
            
            (4
            )Net
                earnings (loss) from discontinued operations
            
            
            2
            
            
            
            (3
            )(Loss)
                gain on disposal of discontinued operations, including income tax
                benefit
                (expense) of $1 and $(8), respectively, and minority interest of
                $1 and
                $35, respectively
            
            
            (1
            )
            
            
            28Earnings
                from discontinued operations
            
            $
            1
            
            
            $
            25





In
      connection with the sale, PEC and PEF provided indemnification against costs
      associated with certain asset performances to Level 3. See general discussion
      of
      guarantees at Note 13B. The ultimate resolution of these matters could result
      in
      adjustments to the gain on sale in future periods.




**E.           Dixie
      Fuels and Other Fuels Business**




On
      March
      1, 2006, we sold our 65 percent interest in Dixie Fuels Limited (Dixie Fuels)
      to
      Kirby Corporation for $16 million in cash. Dixie Fuels operates a fleet of
      four
      ocean-going dry-bulk barge and tugboat units. Dixie Fuels primarily transports
      coal from the lower Mississippi River to Progress Energy’s Crystal River
      facility. We recorded an after-tax gain of $2 million on the sale of Dixie
      Fuels.




The
      accompanying consolidated financial statements have been restated for all
      periods presented to reflect Dixie Fuels and the other fuels business 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
      was less than $1 million for the three months ended September 30, 2006, and
      for
      the nine months ended September 30, 2007 and 2006. We ceased recording
      depreciation upon classification of the assets as discontinued operations.
      After-tax depreciation expense during the nine months ended September 30, 2006,
      was less than $1 million. Results of Dixie Fuels and other fuels business
      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)*
            
            **2007**
            
            
            2006
            
            
            **2007**
            
            
            2006Revenues
            
            **$**
            **–**
            
            
            $
            –
            
            
            **$**
            **–**
            
            
            $
            5Earnings
                before income taxes
            
            ****
            **–**
            
            
            
            6
            
            
            ****
            **1**
            
            
            
            10Income
                tax expense
            
            ****
            **–**
            
            
            
            (3
            )
            
            ****
            **(1**
            **)**
            
            
            (4
            )Net
                earnings from discontinued operations
            
            ****
            **–**
            
            
            
            3
            
            
            ****
            **–**
            
            
            
            6Gain
                on disposal of discontinued operations, including income tax expense
                of
                $1
            
            ****
            **–**
            
            
            
            –
            
            
            ****
            **2**
            
            
            
            2Earnings
                from discontinued operations
            
            **$**
            **–**
            
            
            $
            3
            
            
            **$**
            **2**
            
            
            $
            8





**F.      Coal
      Mining
      Businesses**




On
      November 14, 2005, our board of directors approved a plan to divest of five
      subsidiaries of Progress Fuels engaged in the coal mining business (Coal
      Mining). On May 1, 2006, we sold certain net assets of three of our coal mining
      businesses to Alpha Natural Resources, LLC for gross proceeds of $23 million
      plus a $4 million working capital adjustment. As a result, during the nine
      months ended September 30, 2006, we recorded an after-tax loss of $13 million
      on
      the sale of these assets. The remaining coal mining operations are expected
      to
      be sold by March 31, 2008.




27


The
      accompanying consolidated financial statements have been restated for all
      periods presented to reflect Coal Mining as discontinued operations. Interest
      expense has been allocated to discontinued operations based on the net assets
      of
      the coal mines, assuming a uniform debt-to-equity ratio across our operations.
      Pre-tax interest expense allocated for the nine months ended September 30,
      2006,
      was $1 million. There was less than $1 million allocated for the three months
      ended September 30, 2007 and 2006, and for the nine months ended September
      30,
      2007. We ceased recording depreciation expense upon classification of Coal
      Mining as discontinued operations in November 2005. 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)*
            
            **2007**
            
            
            2006
            
            
            **2007**
            
            
            2006Revenues
            
            **$**
            **8**
            
            
            $
            14
            
            
            **$**
            **22**
            
            
            $
            73(Loss)
                earnings before income taxes
            
            ****
            **(2**
            **)**
            
            
            1
            
            
            ****
            **(13**
            **)**
            
            
            (4
            )Income
                tax benefit
            
            ****
            **1**
            
            
            
            2
            
            
            ****
            **4**
            
            
            
            3Net
                (loss) earnings from discontinued operations
            
            ****
            **(1**
            **)**
            
            
            3
            
            
            ****
            **(9**
            **)**
            
            
            (1
            )Loss
                on disposal of discontinued operations, including income tax benefit
                of
                $17
            
            
            –
            
            
            
            –
            
            
            
            –
            
            
            
            (13
            )(Loss)
                earnings from discontinued operations
            
            **$**
            **(1**
            **)**
            
            $
            3
            
            
            **$**
            **(9**
            **)**
            
            $
            (14
            )





**G.**
            **Progress
                Rail Divestiture**




On
      March
      24, 2005, we completed the sale of Progress Rail Services Corporation (Progress
      Rail) to One Equity Partners LLC, a private equity firm unit of J.P. Morgan
      Chase & Co. Gross cash proceeds from the sale were approximately $429
      million, consisting of $405 million base proceeds plus a working capital
      adjustment. Proceeds from the sale were used to reduce debt.




During
      the nine months ended September 30, 2006, we recorded after-tax loss on disposal
      of $3 million (including income tax benefit of $2 million) in connection with
      guarantees and indemnifications provided by Progress Fuels and Progress Energy
      for certain legal, tax and environmental matters to One Equity Partners, LLC.
      The ultimate resolution of these matters could result in adjustments to the
      loss
      on disposal in future periods. See general discussion of guarantees at Note
      13B.




The
      accompanying consolidated financial statements reflect the operations of
      Progress Rail as discontinued operations.




**H.**
            **Net
                Assets of Discontinued
                Operations**




At
      September 30, 2007, the remaining assets and liabilities of Coal Mining were
      included in net assets of discontinued operations. At December 31, 2006, the
      assets and liabilities of CCO and the remaining assets and liabilities of Coal
      Mining and other fuels business were included in net assets of discontinued
      operations. The major balance sheet classes included in assets and liabilities
      of discontinued operations in the Consolidated Balance Sheets were as
      follows:




28







*(in
                millions)*
            **September
              30, 2007**
            
            
            December
                31, 2006Accounts
                receivable
            
            **$**
            **–**
            
            
            $
            45Inventory
            
            ****
            **2**
            
            
            
            24Other
                current assets
            
            ****
            **1**
            
            
            
            28Total
                property, plant and equipment, net
            
            ****
            **18**
            
            
            
            573Total
                other assets
            
            ****
            **7**
            
            
            
            217Assets
                of discontinued operations
            
            **$**
            **28**
            
            
            $
            887Accounts
                payable
            
            **$**
            **–**
            
            
            $
            43Accrued
                expenses
            
            ****
            **1**
            
            
            
            122Long-term
                liabilities
            
            ****
            **11**
            
            
            
            24Liabilities
                of discontinued operations
            
            **$**
            **12**
            
            
            $
            189





**I.**
            **Ceredo
                Synthetic Fuels
                Interests**




On
      March
      30, 2007, our Progress Fuels subsidiary disposed of its 100 percent ownership
      interest in Ceredo, a subsidiary that produces and sells 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 are received as we produce and sell qualifying
      synthetic fuels on behalf of the buyer during 2007. As of September 30, 2007,
      we
      have received payments of $27 million on the note. Actual proceeds could differ
      based on actual production levels, which shall be determined by the buyer.
      The
      estimated production level of Ceredo subsequent to the transaction is 2.8
      million tons. As of September 30, 2007, we have produced 2.0 million tons.
      The
      note bears interest at a rate equal to the three-month London Inter Bank
      Offering Rate (LIBOR) rate plus 1%. The estimated fair value of the note at
      the
      inception of the transaction was $48 million.




Pursuant
      to the terms of the disposal agreement, the buyer has the right to unwind the
      transaction if an Internal Revenue Service (IRS) reconfirmation private letter
      ruling is not received by November 9, 2007, or if certain adverse changes in
      tax
      law, as defined in the agreement, occur before November 19, 2007. Therefore,
      no
      gain on the disposal will be recognized prior to the expiration of these rights.
      Once these rights expire, deferred gains, if any, from the disposal will be
      recognized over time as we produce and sell qualifying synthetic fuels for
      the
      buyer. The IRS reconfirmation private letter ruling was received on October
      29,
      2007.




On
      the
      date of the transaction, the carrying value of the disposed ownership interest
      totaled $37 million, which consisted primarily of the fair value of crude oil
      call options purchased in January 2007. Subsequent to the disposal, we remain
      the primary beneficiary of Ceredo and continue to consolidate Ceredo in
      accordance with FIN 46R, but we have recorded a 100 percent minority interest.
      Consequently, subsequent to the disposal there is no net earnings impact from
      Ceredo’s operations and our net investment in Ceredo is zero. In connection with
      the disposal, Progress Fuels and Progress Energy provided guarantees and
      indemnifications for certain legal and tax matters to the buyer which reduces
      any potential deferred gain. The ultimate resolution of these matters could
      result in adjustments to the gain, if any, on disposal in future periods. See
      general discussion of guarantees at Note 13B.




**4.**
            **REGULATORY
                MATTERS**




**A.           PEC
      Retail Rate Matters**




**BASE
      RATES**




PEC’s
      base rates are subject to the regulatory jurisdiction of the NCUC and SCPSC.
      In
      June 2002, the North Carolina Clean Smokestacks Act (Clean Smokestacks Act)
      was
      enacted in North Carolina requiring the state's electric utilities to reduce
      the
      emissions of nitrogen oxides (NOx) and sulfur dioxide (SO2) from their
      North
      Carolina coal-fired power plants in phases by 2013. The Clean Smokestacks Act
      freezes North Carolina electric utility base rates for a five-year period ending
      in December 2007, unless there are extraordinary events beyond the control
      of
      the utilities or unless the utilities persistently earn a return substantially
      in excess of the rate of return




29


established
      and found reasonable by the NCUC in the respective utility’s last general rate
      case. Subsequent to 2007, PEC’s current North Carolina base rates will continue
      subject to traditional cost-based rate regulation.




During
      the rate freeze period, the legislation provides 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. For
      the
      three and nine months ended September 30, 2007, PEC recognized amortization
      of
      $8 million and $25 million, respectively. For the three and nine months ended
      September 30, 2006, PEC recognized amortization of $21 million and $65 million,
      respectively. PEC has recognized $560 million in cumulative amortization through
      September 30, 2007. We will record at least the remaining amortization
      requirement of $9 million during the three-month period ending December 31,
      2007.




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 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 Associations (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. We cannot predict the outcome of
      this matter.




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




**FUEL
      COST RECOVERY**




On
      May 2,
      2007, 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 $12 million increase
      in fuel rates for under-recovered fuel costs associated with prior year
      settlements and to meet future expected fuel costs. On June 27, 2007, the SCPSC
      approved a settlement agreement filed jointly by PEC and all other parties
      to
      the proceedings. The settlement agreement resolved all issues and provided
      for a
      $12 million increase in fuel rates. Effective July 1, 2007, residential electric
      bills increased by $1.83 per 1,000 kWhs, or 1.9 percent, for fuel cost recovery.




On
      June
      8, 2007, PEC filed with the NCUC for an increase in the fuel rate charged to
      its
      North Carolina ratepayers. PEC asked the NCUC to approve a $48 million increase
      in fuel rates for under-recovered fuel costs associated with prior year
      settlements, as discussed below. On September 25, 2007, the NCUC approved PEC’s
      petition. The increase took effect October 1, 2007, and increased residential
      electric bills by $1.30 per 1,000 kWhs, or 1.3 percent, for fuel cost recovery.




On
      June
      2, 2006, PEC filed with the NCUC for an increase in the fuel rate charged to
      its
      North Carolina ratepayers. On September 25, 2006, the NCUC approved a settlement
      agreement filed jointly by PEC, the NCUC Public Staff and CIGFUR. The settlement
      agreement provided for a $177 million, or 6.7 percent increase in rates
      effective October 1, 2006. The settlement agreement further provided for rate
      increases of approximately $50 million in 2007 and $30 million in 2008 and
      for
      PEC to collect its existing deferred fuel balance by September 30, 2009. PEC
      initially sought an increase of $292 million, or 11.0 percent, but agreed to
      a
      three-year phase-in of the increase in order to address concerns regarding
      the
      magnitude of the proposed increase. PEC will be allowed to calculate and collect
      interest at 6.0% on an amount equal to the under-recovery resulting from the
      difference between PEC’s fuel factor proposed in its original request to the
      NCUC and the settlement agreement’s fuel factor.




On
      November 21, 2006, CUCA filed an appeal with the North Carolina Tenth District
      Court of Appeals of the NCUC’s September 25, 2006, order on the grounds that the
      NCUC does not have the statutory authority to establish fuel rates for more
      than
      one year. PEC filed a motion to dismiss with the Court of Appeals on March
      22,
      2007. On October 24, 2007, CUCA filed a motion to withdraw their
      appeal.




30


**OTHER
      MATTERS**




PEC
      filed
      petitions on September 14, 2006, and September 22, 2006, with the SCPSC and
      NCUC, respectively, seeking authorization to defer and amortize the respective
      jurisdictional portion of $18 million of previously recorded operation and
      maintenance (O&M) expense relating to certain environmental remediation
      sites (See Note 12A). On October 11, 2006, the SCPSC granted PEC’s petition to
      defer its jurisdictional amount, totaling $3 million, and amortize it over
      a
      five-year period beginning January 1, 2007. On October 19, 2006, the NCUC
      granted PEC’s petition to defer its jurisdictional amount, totaling $15 million,
      and amortize it over a five-year period. However, the NCUC order directed that
      amortization begin in 2006, with an amortization expense of $3 million. As
      a
      result, during the fourth quarter of 2006, PEC reversed $18 million of O&M
      expense, established a regulatory asset and recorded $3 million of amortization
      expense. During the three and nine months ended September 30, 2007, PEC recorded
      $1 million and $2 million, respectively, of amortization expense. Additionally,
      PEC reduced the regulatory asset by $5 million during the nine months ended
      September 30, 2007, based on newly available data regarding certain remediation
      sites and insurance proceeds (See Note 12A).




**B.           PEF
      Retail Rate Matters**




**PASS-THROUGH
      CLAUSE COST RECOVERY**




On
      September 4, 2007, PEF filed a request with the FPSC seeking approval of a
      cost
      adjustment to reflect a projected over-collection of fuel costs in 2007,
      declining projected fuel costs for 2008, and other recovery clause factors.
      PEF
      asked the FPSC to approve a $163 million, or 4.53 percent, decrease in rates
      effective January 1, 2008. This cost adjustment would decrease residential
      bills
      by $5.00 for the first 1,000 kWhs. As discussed in “Other Matters” below,
      residential base rates will increase effective January 1, 2008, by $2.73 for
      the
      first 1,000 kWhs. After considering the net effect of the base rate increase
      and
      the proposed fuel cost adjustment, 2008 residential bills would decrease by
      a
      net amount of $2.27 for the first 1,000 kWhs. The FPSC is scheduled to hold
      hearings on the cost adjustment proposal on November 6, 2007. We cannot predict
      the outcome of this matter.




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, inclusive of interest, over a 12-month period beginning January
      1,
      2008. For the nine months ended September 30, 2007, PEF recorded a pre-tax
      other
      operating expense of $12 million, interest expense of $2 million and an
      associated regulatory liability for the disallowed fuel costs and interest.
      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. PEF is also evaluating
      its options, including an appeal to the Florida Supreme Court of the FPSC’s
      October 10, 2007 order. We cannot predict the outcome of this matter. The FPSC
      also ordered PEF to address whether it was prudent in its 2006 and 2007 coal
      purchases for CR4 and CR5. On October 4, 2007, PEF filed a motion to establish
      a
      separate docket on the prudence of its coal purchases for CR4 and CR5 for the
      years 2006 and 2007. On October 17, 2007, the FPSC granted that motion. The
      OPC
      filed testimony in support of its position to require PEF to refund at least
      $14
      million for alleged excessive fuel recovery charges for 2006 coal purchases.
      PEF
      believes its coal procurement practices have been prudent. We cannot predict
      the
      outcome of this matter.




On
      September 22, 2006, PEF filed a petition with the FPSC for Determination of
      Need
      to uprate Crystal River Unit No. 3 Nuclear Plant (CR3), bid rule exemption
      and
      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 multi-stage uprate will increase
      CR3’s
      gross output by approximately 180 MW by 2012. Several design modifications
      will
      require a license amendment approved by the NRC. The petition filed with the
      FPSC included estimated project




31


costs
      of
      approximately $382 million. These cost estimates may continue to change
      depending upon the results of more detailed engineering and development work
      and
      increased material, labor and equipment costs. On February 8, 2007, the FPSC
      issued an order approving the need certification petition and bid rule
      exemption. The request for recovery through PEF’s fuel recovery clause was
      transferred to a separate docket filed on January 16, 2007. On February 2,
      2007,
      intervenors filed a motion to abate the cost-recovery portion of PEF’s request.
      On February 9, 2007, PEF requested that the FPSC deny the intervenors’ motion as
      legally deficient and without merit. On March 27, 2007, the FPSC denied the
      motion to abate and directed the staff of the FPSC to conduct a hearing to
      determine whether the revenue requirements of the uprate should be recovered
      through the fuel recovery clause. On May 4, 2007, PEF filed amended testimony
      clarifying the scope of the project. The FPSC held a hearing on this matter
      on
      August 7 and 8, 2007. The staff of the FPSC recommended that PEF be allowed
      to
      recover prudent and reasonable costs of Phase 1, instrumentation modifications
      for improved accuracy, estimated at $6 million through the fuel clause. The
      staff of the FPSC recommended that the costs of all other phases, estimated
      at
      $376 million, be considered in a base rate proceeding. On October 19, 2007,
      PEF
      filed a notice of withdrawal of its cost recovery petition with the FPSC. PEF
      intends to re-file a petition in the fourth quarter of this year seeking cost
      recovery under Florida’s comprehensive energy bill enacted in 2006, and the
      FPSC's new nuclear cost recovery rule. We cannot predict the outcome of this
      matter.




**OTHER
      MATTERS**




On
      November 3, 2004, the FPSC approved PEF’s petition for Determination of Need for
      the construction of a fourth unit at PEF’s Hines Energy Complex. Hines Unit 4 is
      needed to maintain electric system reliability and integrity and to continue
      to
      provide adequate electricity to its ratepayers at a reasonable cost. Hines
      Unit
      4 will be a combined cycle unit with a generating capacity of approximately
      461
      MW (summer rating). The estimated total in-service cost of Hines Unit 4 approved
      as part of the Determination of Need was $286 million. If the actual cost is
      less than the original estimate, ratepayers will receive the benefit of such
      cost under-runs. Any costs that exceed this estimate will not be recoverable
      absent, among other things, extraordinary circumstances as found by the FPSC
      in
      subsequent proceedings. The current estimate of in-service cost exceeds the
      initial project estimate due to what we believe to be extraordinary
      circumstances, including higher than anticipated land acquisition costs and
      unforeseen increases in commodity and labor costs. PEF filed a cost-recovery
      petition with the FPSC on April 30, 2007, to recover the full revenue
      requirements of Hines Unit 4, which has a current estimated in-service cost
      of
      $327 million, by increasing base rates $52 million, as provided for in PEF’s
      2005 base rate agreement. Under this rate agreement, the base rate increase
      would become effective upon Hines Unit 4 being placed in service, which PEF
      anticipates will be on December 1, 2007. The 2005 base rate agreement also
      provides that concurrent with the in-service date of Hines Unit 4, PEF will
      transfer the cost of Hines Unit 2 to base rates from the fuel clause. On
      September 27, 2007, the staff of the FPSC recommended that PEF be allowed to
      recover the full in-service costs, including the $41 million cost in excess
      of
      the Determination of Need and increase base rates $52 million effective December
      1, 2007, for Hines Unit 4 and the related transmission facilities. The staff
      also recommended that the base rate changes associated with both Hines Unit
      4
      and Hines Unit 2 be achieved by applying the new rates to energy sales after
      December 1, 2007, thus requiring PEF to pro-rate the changes on customer bills
      rendered in December for customers that had consumption of electricity in both
      November and December. On October 12, 2007, PEF entered into a stipulation
      and
      settlement agreement that was filed with the FPSC. The agreement was reached
      with intervenors in settlement of all issues related to recovery of the revenue
      requirements of Hines Unit 4 and Hines Unit 2 and provides that PEF shall 1)
      increase its base rates for revenue requirements of Hines Unit 2 and Hines
      Unit
      4 as approved in the staff recommendation and 2) simplify the implementation
      of
      the base rate increase by making it effective with the first billing cycle
      in
      January 2008. On October 23, 2007, the FPSC voted to approve the stipulation
      and
      settlement agreement.




On
      October 29, 2007, PEF 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 PEF OATT in order to more accurately reflect the costs
      that PEF incurs in providing transmission service. In the filing, PEF proposed
      to move from a fixed rate 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. PEF is awaiting FERC approval of
      the
      settlement agreement. If approved, the new rates will be effective January
      1,
      2008, and PEF estimates the impact of the new rates will increase 2008 expected
      revenues by $1 million to $2 million.




32


**5.**
            **EQUITY
                AND COMPREHENSIVE
                INCOME**




**A.           Earnings
      Per Common Share**




A
      reconciliation of our weighted-average number of common shares outstanding
      for
      basic and dilutive earnings per share purposes follows:




Three
                Months Ended September 30,
            Nine
                Months Ended September 30,*(in
                millions)*
            **2007**
            2006
            **2007**
            2006Weighted-average
                common shares – basic
            **257**
            251
            **256**
            250Net
                effect of dilutive stock-based compensation plans
            **−**
            −
            **−**
            1Weighted-average
                shares – fully dilutive
            **257**
            251
            **256**
            251





**B.           Comprehensive
      Income**




***Progress
                Energy***Three
                Months Ended September 30,*(in
                millions)*
            
            **2007**
            
            
            2006Net
                income
            
            **$**
            **319**
            
            
            $
            319Other
                comprehensive income (loss)Reclassification
                adjustments included in net incomeChange
                in cash flow hedges (net of tax expense of $- and $20,
                respectively)
            
            ****
            **1**
            
            
            
            32Net
                unrealized losses on cash flow hedges (net of tax benefit of $7 and
                $33,
                respectively)
            
            ****
            **(11**
            **)**
            
            
            (41
            )Other
                comprehensive loss
            
            ****
            **(10**
            **)**
            
            
            (9
            )Comprehensive
                income
            
            **$**
            **309**
            
            
            $
            310





Nine
                Months Ended September 30,*(in
                millions)*
            
            **2007**
            
            
            2006Net
                income
            
            **$**
            **401**
            
            
            $
            317Other
                comprehensive income (loss)Reclassification
                adjustments included in net incomeChange
                in cash flow hedges (net of tax expense of $2 and $19,
                respectively)
            
            ****
            **4**
            
            
            
            31Change
                in unrecognized items for pension and other postretirement benefits
                (net
                of tax expense of $-)
            
            ****
            **2**
            
            
            
            −Net
                unrealized losses on cash flow hedges (net of tax benefit of $5 and
                $17,
                respectively)
            
            ****
            **(9**
            **)**
            
            
            (23
            )Other
                (net of tax benefit of $3)
            
            ****
            **(2**
            **)**
            
            
            −Other
                comprehensive (loss) income
            
            ****
            **(5**
            **)**
            
            
            8Comprehensive
                income
            
            **$**
            **396**
            
            
            $
            325





33





***PEC***Three
                Months Ended September 30,*(in
                millions)*
            
            **2007**
            
            
            2006Net
                income
            
            **$**
            **204**
            
            
            $
            189Other
                comprehensive (loss) incomeNet
                unrealized (losses) gains on cash flow hedges (net of tax benefit
                of $1
                and $-, respectively)
            
            ****
            **(2**
            **)**
            
            
            1Other
                comprehensive (loss) income
            
            ****
            **(2**
            **)**
            
            
            1Comprehensive
                income
            
            **$**
            **202**
            
            
            $
            190Nine
                Months Ended September 30,*(in
                millions)*
            
            **2007**
            
            
            2006Net
                income
            
            **$**
            **416**
            
            
            $
            351Other
                comprehensive lossNet
                unrealized losses on cash flow hedges (net of tax benefit of $1 and
                $1,
                respectively)
            
            ****
            **(1**
            **)**
            
            
            (1
            )Other
                (net of tax benefit of $1)
            
            ****
            **(4**
            **)**
            
            
            −Other
                comprehensive loss
            
            ****
            **(5**
            **)**
            
            
            (1
            )Comprehensive
                income
            
            **$**
            **411**
            
            
            $
            350





***PEF***Three
                Months Ended September 30,*(in
                millions)*
            
            **2007**
            
            
            2006Net
                income
            
            **$**
            **138**
            
            
            $
            125Other
                comprehensive lossNet
                unrealized losses on cash flow hedges (net of tax benefit of $6 and
                $1,
                respectively)
            
            ****
            **(10**
            **)**
            
            
            (2
            )Other
                comprehensive loss
            
            ****
            **(10**
            **)**
            
            
            (2
            )Comprehensive
                income
            
            **$**
            **128**
            
            
            $
            123Nine
                Months Ended September 30,*(in
                millions)*
            
            **2007**
            
            
            2006Net
                income
            
            **$**
            **267**
            
            
            $
            265Other
                comprehensive lossNet
                unrealized losses on cash flow hedges (net of tax benefit of $5 and
                $1,
                respectively)
            
            ****
            **(8**
            **)**
            
            
            (2
            )Other
                comprehensive loss
            
            ****
            **(8**
            **)**
            
            
            (2
            )Comprehensive
                income
            
            **$**
            **259**
            
            
            $
            263





**C.           Common
      Stock**




At
      December 31, 2006, we had 500 million shares of common stock authorized under
      our charter, of which approximately 256 million were outstanding. At December
      31, 2006, we had approximately 54 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, 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 Investor Plus
      Stock Purchase Plan. For the three months ended September 30, 2006, we issued
      approximately 0.3 million shares of common stock resulting in approximately
      $13
      million in proceeds, primarily to meet the requirements of the Investor Plus
      Stock Purchase Plan. For the nine months ended September 30, 2006, we issued
      approximately 1.7 million shares of common stock resulting in




34


approximately
      $73 million in proceeds. Included in these amounts were approximately 1.4
      million shares for proceeds of approximately $58 million 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, 2006, are described
      below.




On
      July
      2, 2007, PEF paid at maturity $85 million of its 6.81% Medium-Term Notes with
      available cash on hand and commercial paper borrowings.




On
      August
      15, 2007, due to extreme volatility in the commercial paper market, Progress
      Energy borrowed $400 million under its $1.13 billion revolving credit agreement
      (RCA) to repay outstanding commercial paper. At September 30, 2007, $400 million
      of Progress Energy’s RCA loan was still outstanding. On October 17, 2007,
      Progress Energy used $200 million of commercial paper proceeds to repay a
      portion of the amount borrowed under the RCA. We will continue to monitor the
      commercial paper and short-term credit markets to determine when to repay the
      remaining balance of the RCA loan, while maintaining an appropriate level of
      liquidity.




On
      August
      15, 2007, due to extreme volatility in the commercial paper market, PEC borrowed
      $300 million under its $450 million RCA and paid at maturity $200 million of
      its
      6.80% First Mortgage Bonds. At September 30, 2007, $150 million of PEC’s RCA
      loan was still outstanding. On October 17, 2007, PEC repaid the remaining $150
      million of its RCA loan using available cash on hand.




On
      September 18, 2007, PEF issued $500 million of First Mortgage Bonds, 6.35%
      Series due 2037 and $250 million of First Mortgage Bonds, 5.80% Series due
      2017.
      The proceeds were used to repay PEF’s utility money pool borrowings and the
      remainder was placed in temporary investments for general corporate use as
      needed.




**7.**
            **UNCERTAIN
                TAX POSITIONS**




***Progress
      Energy***




In
      July
      2006, the FASB issued FIN 48, which clarifies the accounting for income taxes
      by
      prescribing a minimum recognition threshold that a tax position is required
      to
      meet before being recognized in the financial statements. A two-step process
      is
      required for the application of FIN 48; recognition of the tax benefit based
      on
      a “more-likely-than-not” threshold and measurement of the largest amount of tax
      benefit that is greater than 50 percent likely of being realized upon ultimate
      settlement with the taxing authority. We adopted the provisions of FIN 48 on
      January 1, 2007, which was accounted for as a $2 million reduction of the
      January 1, 2007, balance of retained earnings and a $4 million increase in
      regulatory assets. Including the cumulative effect impact, our liability for
      unrecognized tax benefits at January 1, 2007, was $126 million. Of the total
      amount of unrecognized tax benefits at January 1, 2007, $24 million would have
      affected the effective tax rate for income from continuing operations, if
      recognized. Primarily due to the closure of certain tax years in the second
      quarter, at June 30, 2007, our liability for unrecognized tax benefits decreased
      to $84 million and the amount of unrecognized tax benefits that, if recognized,
      would affect the effective tax rate for income from continuing operations
      decreased to $6 million. We did not record any material changes for the three
      months ended September 30, 2007.




We
      and
      our subsidiaries file income tax returns in the U.S. federal jurisdiction,
      and
      various state jurisdictions. Our open federal tax years are from 2004 forward
      and our open state tax years in our major jurisdictions are generally from
      1992
      forward. The IRS is currently examining our federal tax returns for years 2004
      and 2005. We cannot predict when those examinations will be completed. We are
      not aware of any tax positions for which it is reasonably possible that the
      total amounts of unrecognized tax benefits will significantly increase or
      decrease during the twelve-month period ending September 30, 2008.




We
      include interest expense related to unrecognized tax benefits in interest
      charges and we include penalties in other, net on the Consolidated Statements
      of
      Income. As of January 1, 2007, we had accrued $24 million for interest and
      penalties. As of September 30, 2007, we have accrued $20 million for interest
      and penalties.




35


***PEC***




PEC
      adopted the provisions of FIN 48 on January 1, 2007, which was accounted for
      as
      a $6 million reduction of the January 1, 2007, balance of retained earnings.
      Including the cumulative effect impact, PEC’s liability for unrecognized tax
      benefits at January 1, 2007, was $43 million. Of the total amount of
      unrecognized tax benefits at January 1, 2007, $9 million would have affected
      the
      effective tax rate, if recognized. Primarily due to the closure of certain
      tax
      years in the second quarter, at June 30, 2007, PEC’s liability for unrecognized
      tax benefits decreased to $29 million. At June 30, 2007, the amount of
      unrecognized tax benefits that, if recognized, would affect the effective tax
      rate decreased to $7 million. PEC did not record any material changes for the
      three months ended September 30, 2007.




We
      file
      consolidated federal and state income tax returns that include PEC. In addition,
      PEC files stand-alone tax returns in various state jurisdictions. PEC’s open
      federal tax years are from 2004 forward and PEC’s open state tax years in our
      major jurisdictions are generally from 1992 forward. The IRS is currently
      examining our federal tax returns for years 2004 and 2005. PEC cannot predict
      when those examinations will be completed. PEC is not aware of any tax positions
      for which it is reasonably possible that the total amounts of unrecognized
      tax
      benefits will significantly increase or decrease during the twelve-month period
      ending September 30, 2008.




PEC
      includes interest expense related to unrecognized tax benefits in interest
      charges and includes penalties in other, net on the Consolidated Statements
      of
      Income. As of January 1, 2007, PEC had accrued $4 million for interest and
      penalties. PEC did not record any material changes at September 30,
      2007.




***PEF***




PEF
      adopted the provisions of FIN 48 on January 1, 2007, which was accounted for
      as
      a $1 million reduction of the January 1, 2007, balance of retained earnings
      and
      a $4 million increase in regulatory assets. Including the cumulative effect
      impact, PEF’s liability for unrecognized tax benefits at January 1, 2007, was
      $72 million. Of the total amount of unrecognized tax benefits at January 1,
      2007, $4 million would have affected the effective tax rate, if recognized.
      Primarily due to the closure of certain tax years in the second quarter, at
      June
      30, 2007, the PEF liability for unrecognized tax benefits decreased to $56
      million and the amount of unrecognized tax benefits that, if recognized, would
      affect the effective tax rate decreased to $1 million. PEF did not record any
      material changes for the three months ended September 30, 2007.




We
      file
      consolidated federal and state income tax returns that include PEF. PEF’s open
      federal tax years are from 2004****forward and PEF’s open
      state tax years are generally from 1992 forward. The IRS is currently examining
      our federal tax returns for years 2004 and 2005. PEF cannot predict when those
      examinations will be completed. PEF is not aware of any tax positions for which
      it is reasonably possible that the total amounts of unrecognized tax benefits
      will significantly increase or decrease during the twelve-month period ending
      September 30, 2008.




Pursuant
      to a regulatory order, PEF records interest expense related to unrecognized
      tax
      benefits as a regulatory asset, which is amortized over a three-year period,
      with the amortization included in interest charges on the Statements of Income.
      Penalties are included in other, net on the Statements of Income. At January
      1,
      2007, PEF had accrued $7 million for interest and penalties. At September 30,
      2007, PEF had accrued $17 million for interest and penalties.




**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:




36


***Progress
                Energy***Pension
                Benefits
            
            
            Other
                Postretirement BenefitsThree
                Months Ended September 30,*(in
                millions)*
            
            **2007**
            
            
            2006
            
            
            **2007**
            
            
            2006Service
                cost
            
            **$**
            **13**
            
            
            $
            10
            
            
            **$**
            **2**
            
            
            $
            2Interest
                cost
            
            ****
            **31**
            
            
            
            30
            
            
            ****
            **6**
            
            
            
            8Expected
                return on plan assets
            
            ****
            **(38**
            **)**
            
            
            (39
            )
            
            ****
            **(1**
            **)**
            
            
            (2
            )Amortization
                of actuarial loss (gain) (a)
            
            ****
            **4**
            
            
            
            1
            
            
            ****
            **(2**
            **)**
            
            
            (1
            )Other
                amortization, net (a)
            
            
            –
            
            
            
            –
            
            
            ****
            **1**
            
            
            
            1Net
                periodic cost
            
            **$**
            **10**
            
            
            $
            2
            
            
            **$**
            **6**
            
            
            $
            8Pension
                Benefits
            
            
            Other
                Postretirement BenefitsNine
                Months Ended September 30,*(in
                millions)*
            
            **2007**
            
            
            2006
            
            
            **2007**
            
            
            2006Service
                cost
            
            **$**
            **35**
            
            
            $
            34
            
            
            **$**
            **5**
            
            
            $
            6Interest
                cost
            
            ****
            **92**
            
            
            
            88
            
            
            ****
            **24**
            
            
            
            25Expected
                return on plan assets
            
            ****
            **(116**
            **)**
            
            
            (111
            )
            
            ****
            **(4**
            **)**
            
            
            (4
            )Amortization
                of actuarial loss (a)
            
            ****
            **11**
            
            
            
            13
            
            
            ****
            **1**
            
            
            
            3Other
                amortization, net (a)
            
            ****
            **1**
            
            
            
            –
            
            
            ****
            **4**
            
            
            
            4Net
                periodic cost
            
            **$**
            **23**
            
            
            $
            24
            
            
            **$**
            **30**
            
            
            $
            34





(a)      Adjusted
      to reflect PEF’s rate treatment. See Note 16B in the 2006 Form
      10-K.





***PEC***Pension
                Benefits
            
            
            Other
                Postretirement BenefitsThree
                Months Ended September 30,*(in
                millions)*
            
            **2007**
            
            
            2006
            
            
            **2007**
            
            
            2006Service
                cost
            
            **$**
            **7**
            
            
            $
            5
            
            
            **$**
            **2**
            
            
            $
            1Interest
                cost
            
            ****
            **14**
            
            
            
            14
            
            
            ****
            **2**
            
            
            
            4Expected
                return on plan assets
            
            ****
            **(14**
            **)**
            
            
            (16
            )
            
            ****
            **(1**
            **)**
            
            
            (1
            )Amortization
                of actuarial loss (gain)
            
            ****
            **4**
            
            
            
            2
            
            
            ****
            **(2**
            **)**
            
            
            (1
            )Net
                periodic cost
            
            **$**
            **11**
            
            
            $
            5
            
            
            **$**
            **1**
            
            
            $
            3Pension
                Benefits
            
            
            Other
                Postretirement BenefitsNine
                Months Ended September 30,*(in
                millions)*
            
            **2007**
            
            
            2006
            
            
            **2007**
            
            
            2006Service
                cost
            
            **$**
            **17**
            
            
            $
            16
            
            
            **$**
            **4**
            
            
            $
            3Interest
                cost
            
            ****
            **42**
            
            
            
            39
            
            
            ****
            **11**
            
            
            
            12Expected
                return on plan assets
            
            ****
            **(45**
            **)**
            
            
            (44
            )
            
            ****
            **(3**
            **)**
            
            
            (3
            )Amortization
                of actuarial loss
            
            ****
            **9**
            
            
            
            8
            
            
            
            –
            
            
            
            2Other
                amortization, net
            
            ****
            **2**
            
            
            
            1
            
            
            ****
            **1**
            
            
            
            1Net
                periodic cost
            
            **$**
            **25**
            
            
            $
            20
            
            
            **$**
            **13**
            
            
            $
            15





37





***PEF***Pension
                Benefits
            
            
            Other
                Postretirement BenefitsThree
                Months Ended September 30,*(in
                millions)*
            
            **2007**
            
            
            2006
            
            
            **2007**
            
            
            2006Service
                cost
            
            **$**
            **5**
            
            
            $
            4
            
            
            **$**
            –
            
            
            $
            1Interest
                cost
            
            ****
            **13**
            
            
            
            12
            
            
            ****
            **4**
            
            
            
            3Expected
                return on plan assets
            
            ****
            **(21**
            **)**
            
            
            (21
            )
            
            
            –
            
            
            
            –Amortization
                of actuarial gain
            
            
            –
            
            
            
            (1
            )
            
            
            –
            
            
            
            –Other
                amortization, net
            
            
            –
            
            
            
            –
            
            
            ****
            **1**
            
            
            
            1Net
                periodic (benefit) cost
            
            **$**
            **(3**
            **)**
            
            $
            (6
            )
            
            **$**
            **5**
            
            
            $
            5Pension
                Benefits
            
            
            Other
                Postretirement BenefitsNine
                Months Ended September 30,*(in
                millions)*
            
            **2007**
            
            
            2006
            
            
            **2007**
            
            
            2006Service
                cost
            
            **$**
            **12**
            
            
            $
            12
            
            
            **$**
            **1**
            
            
            $
            2Interest
                cost
            
            ****
            **39**
            
            
            
            37
            
            
            ****
            **11**
            
            
            
            10Expected
                return on plan assets
            
            ****
            **(63**
            **)**
            
            
            (58
            )
            
            ****
            **(1**
            **)**
            
            
            (1
            )Amortization
                of actuarial loss
            
            
            –
            
            
            
            2
            
            
            ****
            **1**
            
            
            
            1Other
                amortization, net
            
            
            –
            
            
            
            (1
            )
            
            ****
            **3**
            
            
            
            3Net
                periodic (benefit) cost
            
            **$**
            **(12**
            **)**
            
            $
            (8
            )
            
            **$**
            **15**
            
            
            $
            15





**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 3A, our subsidiary, PVI, entered into a series of transactions
      to sell or assign substantially all of its CCO physical and commercial assets
      and liabilities. On June 1, 2007, PVI closed the transaction involving the
      assignment of a contract portfolio consisting of 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. The sale of the generation
      assets closed on June 11, 2007. Additionally, we sold Gas on October 2, 2006
      (See Note 3B). Due to these divestitures, management determined that it was
      no
      longer probable that the forecasted transactions underlying certain derivative
      contracts would be fulfilled and cash flow hedge accounting for the contracts
      was discontinued beginning in the second quarter of 2006 for Gas and in the
      fourth quarter of 2006 for CCO.




At
      September 30, 2007, due to the closing of the transactions discussed above,
      our
      discontinued operations did not have outstanding positions in derivative
      instruments. At December 31, 2006, derivative assets of $107 million were
      included in assets of discontinued operations and derivative liabilities of
      $31
      million were included in liabilities of discontinued operations on the
      Consolidated Balance Sheet. For the three months ended September 30, 2007,
      there
      were no material net gains and losses from derivative instruments included
      in
      discontinued operations on the Consolidated Statements of Income. For the nine
      months ended September 30, 2007, after-tax gains from derivative instruments
      of
      $88 million were included in discontinued operations on the Consolidated
      Statements of Income. For the three and nine months ended September 30, 2006,
      after-tax losses from derivative instruments of $30 million and $39 million,
      respectively, were included in discontinued operations on the Consolidated
      Statements of Income. For the three and nine months ended September 30, 2007,
      there were no reclassifications to earnings due to the




38


discontinuance
      of the related cash flow hedges. For the three months ended September 30, 2006,
      there were no reclassifications to earnings due to the discontinuance of the
      related cash flow hedges. For the nine months ended September 30, 2006, $7
      million in after-tax losses were reclassified to earnings due to the
      discontinuance of the related cash flow hedges in anticipation of the sale
      of
      Gas.




**A.           Commodity
      Derivatives**




**GENERAL**




Most
      of
      our commodity contracts are not derivatives pursuant to Statement of Financial
      Accounting Standards No. 133, “Accounting for Derivative and Hedging Activities”
(SFAS No. 133) or qualify 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,
      2007, and December 31, 2006, the remaining liability was $11 million and $14
      million, respectively.




**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.




On
      January 8, 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 is 25 million barrels and will provide 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
      are marked-to-market with changes in fair value recorded through earnings from
      synthetic fuels production. Approximately 34 percent of the notional quantity
      of
      these contracts was entered into by Ceredo. As discussed in Notes 1C and 3I,
      we
      disposed of our 100 percent ownership interest in Ceredo on March 30, 2007.
      Progress Energy is the primary beneficiary of, and continues to consolidate
      Ceredo in accordance with FIN 46R, but we have recorded a 100 percent minority
      interest. Consequently, subsequent to the disposal there is no net earnings
      impact for the contracts entered into by Ceredo. At September 30, 2007, the
      fair
      value of these contracts was recorded as a $170 million short-term derivative
      asset position, including $58 million at Ceredo. The fair value of these
      contracts was included in derivative assets on the Consolidated Balance Sheet.
      During the three and nine months ended September 30, 2007, we recorded net
      pre-tax gains of $74 million and $105 million, respectively, in diversified
      business revenues related to these contracts, including net pre-tax gains of
      $26
      million and $21 million, respectively, at Ceredo subsequent to disposal of
      our
      100 percent ownership interest.




The
      Utilities have derivative instruments related to their exposure to price
      fluctuations on fuel oil and natural gas purchases. These instruments receive
      regulatory accounting treatment. 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.




At
      September 30, 2007, the fair value of PEC’s commodity derivative instruments was
      recorded as a $3 million long-term derivative asset position included in other
      assets and deferred debits and a $5 million short-term derivative liability
      position included in other current liabilities on the Consolidated Balance
      Sheet. At December 31, 2006, PEC did not have material outstanding positions
      in
      such contracts.




At
      September 30, 2007, the fair value of PEF’s commodity derivative instruments was
      recorded as a $14 million short-term derivative asset position included in
      prepayments and other current assets, a $12 million long-term derivative asset
      position included in other assets and deferred debits, a $31 million short-term
      derivative liability position included in derivative liabilities, and a $5
      million long-term derivative liability position included in other




39


liabilities
      and deferred credits on the PEF Balance Sheet. At December 31, 2006, the fair
      value of such instruments was recorded as a $2 million long-term derivative
      asset position included in other assets and deferred debits, an $87 million
      short-term derivative liability position included in derivative liabilities
      and
      a $36 million long-term derivative liability position included in other
      liabilities and deferred credits on the PEF Balance Sheet.




**CASH
      FLOW HEDGES**




Our
      subsidiaries designate 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
      natural gas and power for our forecasted purchases and sales. Realized gains
      and
      losses are recorded net in operating revenues or operating expenses, as
      appropriate. At September 30, 2007, and December 31, 2006, we and the Utilities
      did not have material outstanding positions in such contracts. The ineffective
      portion of commodity cash flow hedges for the three and nine months ended
      September 30, 2007 and 2006, was not material to our or the Utilities’ results
      of operations.




At
      September 30, 2007, and December 31, 2006, the amount recorded in our or PEC’s
      accumulated other comprehensive income (AOCI) related to commodity cash flow
      hedges was not material and PEF had no amount recorded in AOCI related to
      commodity cash flow hedges.




Our
      discontinued operations did not have material outstanding positions in commodity
      cash flow hedges at September 30, 2007, or December 31, 2006.




**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.




The
      fair
      values of interest rate hedges at September 30, 2007, and December 31, 2006,
      were as follows:




**September
              30, 2007**
            
            December 31,
              2006*(in
                millions)*
            
            **Progress
                Energy**
            
            
            **PEC**
            
            
            **PEF**
            
            
            Progress
                Energy
            
            
            PEC
            
            
            PEFInterest
                rate cash flow hedgesFair
                value of assets
            
            **$**
            **–**
            
            
            **$**
            **–**
            
            
            **$**
            **–**
            
            
            $
            –
            
            
            $
            –
            
            
            $
            –Fair
                value of liabilities
            
            ****
            **(4**
            **)**
            
            ****
            **(4**
            **)**
            
            ****
            **–**
            
            
            
            (2
            )
            
            
            (1
            )
            
            
            (1
            )Interest
                rate fair value hedgesFair
                value of assets
            
            ****
            **–**
            
            
            ****
            **–**
            
            
            ****
            **–**
            
            
            
            –
            
            
            
            –
            
            
            
            –Fair
                value of liabilities
            
            ****
            **–**
            
            
            ****
            **–**
            
            
            ****
            **–**
            
            
            
            (1
            )
            
            
            –
            
            
            
            –







**CASH
      FLOW HEDGES**




Gains
      and
      losses from cash flow hedges are recorded in AOCI and amounts reclassified
      to
      earnings are included in net interest charges as the hedged transactions occur.
      Amounts in AOCI related to terminated hedges are reclassified to earnings as
      the
      interest expense is recorded. The ineffective portion of interest rate cash
      flow
      hedges for the three and nine months ended September 30, 2007 and 2006, was
      not
      material to our or the Utilities’ results of operations.




40


The
      following table presents selected information related to our interest rate
      cash
      flow hedges at September 30, 2007:




*(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)
            
            $
            (20
            )
            
            $
            (7
            )
            
            $
            (9
            )Portion
                expected to be reclassified to earnings during the next12
                months(b)
            
            
            (2
            )
            
            
            (1
            )
            
            
            –





(a)      Includes
      amounts related to terminated hedges.


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





At
      September 30, 2007, we had $100 million notional of interest rate cash flow
      hedges at PEC. Subsequently, on October 24, 2007, PEC entered into $100 million
      notional of forward starting swaps to mitigate exposure to interest rate risk
      in
      anticipation of future debt issuances. At December 31, 2006, we had $100 million
      notional of interest rate cash flow hedges, including $50 million notional
      at
      PEC and $50 million notional at PEF.




PEF
      entered into a $25 million notional forward starting swap in July 2007, $150
      million notional in forward starting swaps in June 2007, and a $50 million
      forward starting swap in February 2007 to mitigate exposure to interest rate
      risk in anticipation of future debt issuances. All of PEF’s forward starting
      swaps were terminated on September 13, 2007, in conjunction with PEF’s issuance
      of $500 million of First Mortgage Bonds, 6.35% Series due 2037 and $250 million
      of First Mortgage Bonds, 5.80% Series due 2017. On July 30, 2007, PEC entered
      into a $50 million notional forward starting swap to mitigate exposure to
      interest rate risk in anticipation of future debt issuances. On September 25,
      2007, PEC amended its 10-year forward starting swap in order to move the
      maturity date from October 1, 2017 to April 1, 2018.




At
      December 31, 2006, including amounts related to terminated hedges, we had $14
      million of after-tax deferred losses, including $5 million of after-tax deferred
      losses at PEC and $1 million of after-tax deferred losses at PEF, recorded
      in
      AOCI related to interest rate cash flow hedges.




**FAIR
      VALUE HEDGES**




For
      interest rate fair value hedges, the change in the fair value of the hedging
      derivative is recorded in net interest charges and is offset by the change in
      the fair value of the hedged item. At September 30, 2007, we had no open
      interest rate fair value hedges. At December 31, 2006, we had a $50 million
      notional interest rate fair value hedge, which was terminated on September
      26,
      2007. At September 30, 2007, and December 31, 2006, the Utilities had no open
      interest rate fair value hedges.




**10.**
            **FINANCIAL
                INFORMATION BY BUSINESS
                SEGMENT**




Our
      reportable segments are: PEC, PEF, and Coal and Synthetic Fuels.




Our
      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.




Our
      Coal
      and Synthetic Fuels segment is primarily engaged in the production and sale
      of
      coal-based solid synthetic fuels (as defined under the Code), the operation
      of
      synthetic fuels facilities for third parties, and coal terminal services. On
      September 14, 2007, we idled production of synthetic fuels at our majority-owned
      synthetic fuels facilities due to the current high level of oil prices. On
      October 12, 2007, based upon the continued high level of oil prices, unfavorable
      oil price projections through the end of 2007, and the expiration of the current
      synthetic fuels tax credit program at the end of 2007, we decided to permanently
      cease production of synthetic fuels at our majority-owned facilities. The
      operation of synthetic fuels facilities on the behalf of third parties is
      expected to continue through the end of the current synthetic fuels tax credit
      program.




41


In
      addition to the reportable operating segments, the Corporate and Other segment
      includes the operations of the Parent and PESC as well as other nonregulated
      business areas. These nonregulated business areas do not separately meet the
      disclosure requirements of SFAS No. 131, “Disclosures about Segments of an
      Enterprise and Related Information.” The profit or loss of the identified
      segments plus the profit or loss of Corporate and Other represents our total
      income from continuing operations.




Income
      and assets of discontinued operations are 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:




IncomeRevenues
            
            
            (Loss)
                from*(in
                millions)*
            
            Unaffiliated
            
            
            Intersegment
            
            
            Total
            
            
            Continuing
                Operations
            
            
            Assets**Three
                Months Ended September 30, 2007****PEC**
            
            **$**
            **1,286**
            
            
            **$**
            **–**
            
            
            **$**
            **1,286**
            
            
            **$**
            **203**
            
            
            **$**
            **12,175****PEF**
            
            ****
            **1,456**
            
            
            ****
            **–**
            
            
            ****
            **1,456**
            
            
            ****
            **138**
            
            
            ****
            **9,896****Coal
                and Synthetic Fuels (a)**
            
            ****
            **356**
            
            
            ****
            **–**
            
            
            ****
            **356**
            
            
            ****
            **(16**
            **)**
            
            ****
            **672****Corporate
                and Other**
            
            ****
            **2**
            
            
            ****
            **99**
            
            
            ****
            **101**
            
            
            ****
            **(6**
            **)**
            
            ****
            **16,170****Eliminations**
            
            ****
            **–**
            
            
            ****
            **(99**
            **)**
            
            ****
            **(99**
            **)**
            
            ****
            **–**
            
            
            ****
            **(12,368**
            **)****Totals**
            
            **$**
            **3,100**
            
            
            **$**
            **–**
            
            
            **$**
            **3,100**
            
            
            **$**
            **319**
            
            
            **$**
            **26,545**Three
                Months Ended September 30, 2006PEC
            
            $
            1,200
            
            
            $
            –
            
            
            $
            1,200
            
            
            $
            188PEF
            
            
            1,399
            
            
            
            –
            
            
            
            1,399
            
            
            
            125Coal
                and Synthetic Fuels (a)
            
            
            177
            
            
            
            88
            
            
            
            265
            
            
            
            7Corporate
                and Other
            
            
            –
            
            
            
            97
            
            
            
            97
            
            
            
            (37
            )Eliminations
            
            
            –
            
            
            
            (185
            )
            
            
            (185
            )
            
            
            –Totals
            
            $
            2,776
            
            
            $
            –
            
            
            $
            2,776
            
            
            $
            283


IncomeRevenues
            
            
            (Loss)
                from*(in
                millions)*
            
            Unaffiliated
            
            
            Intersegment
            
            
            Total
            
            
            Continuing
                Operations
            
            
            Assets**Nine
                Months Ended September 30, 2007****PEC**
            
            **$**
            **3,340**
            
            
            **$**
            **–**
            
            
            **$**
            **3,340**
            
            
            **$**
            **414**
            
            
            **$**
            **12,175****PEF**
            
            ****
            **3,596**
            
            
            ****
            **–**
            
            
            ****
            **3,596**
            
            
            ****
            **266**
            
            
            ****
            **9,896****Coal
                and Synthetic Fuels (a)**
            
            ****
            **897**
            
            
            ****
            **2**
            
            
            ****
            **899**
            
            
            ****
            **56**
            
            
            ****
            **672****Corporate
                and Other**
            
            ****
            **7**
            
            
            ****
            **286**
            
            
            ****
            **293**
            
            
            ****
            **(66**
            **)**
            
            ****
            **16,170****Eliminations**
            
            ****
            **–**
            
            
            ****
            **(288**
            **)**
            
            ****
            **(288**
            **)**
            
            ****
            **–**
            
            
            ****
            **(12,368**
            **)****Totals**
            
            **$**
            **7,840**
            
            
            **$**
            **–**
            
            
            **$**
            **7,840**
            
            
            **$**
            **670**
            
            
            **$**
            **26,545**Nine
                Months Ended September 30, 2006PEC
            
            $
            3,114
            
            
            $
            –
            
            
            $
            3,114
            
            
            $
            349PEF
            
            
            3,553
            
            
            
            –
            
            
            
            3,553
            
            
            
            264Coal
                and Synthetic Fuels (a)
            
            
            630
            
            
            
            251
            
            
            
            881
            
            
            
            (83
            )Corporate
                and Other
            
            
            –
            
            
            
            289
            
            
            
            289
            
            
            
            (143
            )Eliminations
            
            
            –
            
            
            
            (540
            )
            
            
            (540
            )
            
            
            –Totals
            
            $
            7,297
            
            
            $
            –
            
            
            $
            7,297
            
            
            $
            387





(a)
            Coal
                and Synthetic Fuels includes revenues of synthetic fuels facilities
                that
                are operated on behalf of third
                parties.





42


**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. AFUDC equity represents the estimated equity costs of
      capital funds necessary to finance the construction of new regulated assets.
      Contingent value obligations (CVOs) unrealized gain or loss is due to changes
      in
      the fair market value of the liability. See Note 15 in the 2006 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
                Energy***Three
                  Months Ended
                September
                  30,
            
            
            Nine
                  Months Ended
                September
                  30,*(in
                millions)*
            
            **2007**
            
            
            2006
            
            
            **2007**
            
            
            2006Other
                incomeNonregulated
                energy and delivery services income
            
            **$**
            **2**
            
            
            $
            4
            
            
            **$**
            **25**
            
            
            $
            27DIG
                Issue C20 amortization (see Note 9)
            
            ****
            **1**
            
            
            
            2
            
            
            ****
            **3**
            
            
            
            4CVOs
                unrealized gain
            
            ****
            **1**
            
            
            ****
            **−**
            
            
            ****
            **2**
            
            
            ****
            **−**Gain
                on sale of property, net
            
            ****
            **3**
            
            
            ****
            **−**
            
            
            ****
            **1**
            
            
            ****
            **−**Gain
                on sale of Level 3 stock(a)
            
            ****
            **−**
            
            
            ****
            **−**
            
            
            ****
            **−**
            
            
            
            32Investment
                gains
            
            ****
            **2**
            
            
            
            1
            
            
            ****
            **5**
            
            
            
            3Income
                from equity investments
            
            ****
            **1**
            
            
            ****
            **−**
            
            
            ****
            **7**
            
            
            ****
            **−**AFUDC
                equity
            
            ****
            **14**
            
            
            
            6
            
            
            ****
            **34**
            
            
            
            13Other
            
            ****
            **2**
            
            
            
            5
            
            
            ****
            **10**
            
            
            
            16Total
                other income
            
            ****
            **26**
            
            
            
            18
            
            
            ****
            **87**
            
            
            
            95Other
                expenseNonregulated
                energy and delivery services expenses
            
            ****
            **7**
            
            
            
            7
            
            
            ****
            **19**
            
            
            
            22Donations
            
            ****
            **6**
            
            
            
            3
            
            
            ****
            **16**
            
            
            
            15Investment
                losses
            
            ****
            **4**
            
            
            ****
            **−**
            
            
            ****
            **4**
            
            
            ****
            **−**Loss
                from equity investments
            
            ****
            **1**
            
            
            
            3
            
            
            ****
            **2**
            
            
            
            6CVOs
                unrealized loss
            
            ****
            **−**
            
            
            
            3
            
            
            ****
            **4**
            
            
            
            25Indemnification
                liability (See Note 12)
            
            ****
            **−**
            
            
            
            8
            
            
            ****
            **−**
            
            
            
            13Other
            
            ****
            **1**
            
            
            
            3
            
            
            ****
            **9**
            
            
            
            15Total
                other expense
            
            ****
            **19**
            
            
            
            27
            
            
            ****
            **54**
            
            
            
            96Other,
                net
            
            **$**
            **7**
            
            
            $
            (9
            )
            
            **$**
            **33**
            
            
            $
            (1
            )





(a)
            Other
                income includes pre-tax gains of $32 million for the nine months
                ended
                September 30, 2006, from the sale of approximately 20 million shares
                of
                Level 3 stock received as part of the sale of our interest in PT
                LLC (See
                Note 3D). These gains are prior to the consideration of minority
                interest.




43







***PEC***Three
                Months Ended
              September
                30,
            
            
            Nine
                Months Ended
              September
                30,*(in
                millions)*
            
            **2007**
            
            
            2006
            
            
            **2007**
            
            
            2006Other
                incomeNonregulated
                energy and delivery services income
            
            **$**
            **(3**
            **)**
            
            $
            (2
            )
            
            **$**
            **6**
            
            
            $
            8DIG
                Issue C20 amortization (see Note 9)
            
            ****
            **1**
            
            
            
            2
            
            
            ****
            **3**
            
            
            
            4Income
                from equity investments
            
            ****
            **1**
            
            
            ****
            **−**
            
            
            ****
            **3**
            
            
            ****
            **−**Investment
                gains
            
            ****
            **2**
            
            
            
            2
            
            
            ****
            **3**
            
            
            
            2AFUDC
                equity
            
            ****
            **2**
            
            
            ****
            **−**
            
            
            ****
            **7**
            
            
            
            2Other
            
            ****
            **2**
            
            
            ****
            **−**
            
            
            ****
            **7**
            
            
            
            7Total
                other income
            
            ****
            **5**
            
            
            
            2
            
            
            ****
            **29**
            
            
            
            23Other
                expenseNonregulated
                energy and delivery services expenses
            
            ****
            **3**
            
            
            
            2
            
            
            ****
            **6**
            
            
            
            6Donations
            
            ****
            **1**
            
            
            
            1
            
            
            ****
            **6**
            
            
            
            8Loss
                from equity investments
            
            ****
            **−**
            
            
            ****
            **−**
            
            
            ****
            **1**
            
            
            
            1Investment
                losses
            
            ****
            **2**
            
            
            ****
            **−**
            
            
            ****
            **3**
            
            
            
            3Indemnification
                liability
            
            ****
            **−**
            
            
            
            8
            
            
            ****
            **−**
            
            
            
            13Other
            
            ****
            **−**
            
            
            
            1
            
            
            ****
            **4**
            
            
            
            4Total
                other expense
            
            ****
            **6**
            
            
            
            12
            
            
            ****
            **20**
            
            
            
            35Other,
                net
            
            **$**
            **(1**
            **)**
            
            $
            (10
            )
            
            **$**
            **9**
            
            
            $
            (12
            )





***PEF***Three
                Months Ended
              September
                30,
            
            
            Nine
                Months Ended
              September
                30,*(in
                millions)*
            
            **2007**
            
            
            2006
            
            
            **2007**
            
            
            2006Other
                incomeNonregulated
                energy and delivery services income
            
            **$**
            **5**
            
            
            $
            6
            
            
            **$**
            **19**
            
            
            $
            19Investment
                gains
            
            ****
            **−**
            
            
            ****
            **−**
            
            
            ****
            **2**
            
            
            
            1AFUDC
                equity
            
            ****
            **12**
            
            
            
            6
            
            
            ****
            **27**
            
            
            
            11Other
            
            ****
            **1**
            
            
            ****
            **−**
            
            
            ****
            **1**
            
            
            
            1Total
                other income
            
            ****
            **18**
            
            
            
            12
            
            
            ****
            **49**
            
            
            
            32Other
                expenseNonregulated
                energy and delivery services expenses
            
            ****
            **4**
            
            
            
            5
            
            
            ****
            **13**
            
            
            
            15Donations
            
            ****
            **1**
            
            
            
            1
            
            
            ****
            **4**
            
            
            
            7Investment
                losses
            
            ****
            **1**
            
            
            ****
            **−**
            
            
            ****
            **1**
            
            
            ****
            **−**Loss
                from equity investments
            
            ****
            **−**
            
            
            ****
            **−**
            
            
            ****
            **1**
            
            
            
            1Other
            
            ****
            **−**
            
            
            ****
            **−**
            
            
            ****
            **3**
            
            
            
            1Total
                other expense
            
            ****
            **6**
            
            
            
            6
            
            
            ****
            **22**
            
            
            
            24Other,
                net
            
            **$**
            **12**
            
            
            $
            6
            
            
            **$**
            **27**
            
            
            $
            8





44





**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
      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 potential
      PRPs
      and insurance carriers and plan to submit claims for cost recovery where
      appropriate. The outcome of these potential claims cannot be predicted. No
      material claims are currently pending. A discussion of sites by legal entity
      follows.




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




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 included in other liabilities
      and deferred credits on the Balance Sheets, were:




*(in
                millions)*
            
            **September
                30, 2007**
            
            
            December
                31, 2006***PEC***MGP
                and other sites(a)
            
            **$**
            **16**
            
            
            $
            22***PEF***Remediation
                of distribution and substation transformers
            
            ****
            **36**
            
            
            
            43MGP
                and other sites
            
            ****
            **18**
            
            
            
            18Total
                PEF environmental remediation accruals(b)
            
            ****
            **54**
            
            
            
            61Progress
                Energy nonregulated operations
            
            ****
            **1**
            
            
            
            3Total
                Progress Energy environmental remediation accruals
            
            **$**
            **71**
            
            
            $
            86





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


(b)
            Expected
                to be paid out over one to fifteen
                years.





45


***Progress
      Energy***




In
      addition to the Utilities’ sites, discussed under “PEC” and “PEF” below, our
      environmental sites include the following related to our nonregulated
      operations.




In
      2001,
      we, through our Progress Fuels subsidiary, established an accrual to address
      indemnities and retained an environmental liability associated with the sale
      of
      our Inland Marine Transportation business. For the nine months ended September
      30, 2007, the accrual was reduced by $2 million due to a reduction in the
      anticipated scope of work based on responses from regulatory agencies.
      Expenditures related to this liability were not material for the three and
      nine
      months ended September 30, 2007 and 2006.




On
      March
      24, 2005, we completed the sale of our Progress Rail subsidiary. In connection
      with the sale, we incurred indemnity obligations related to certain pre-closing
      liabilities, including certain environmental matters (See discussion under
      Guarantees in Note 13B).




***PEC***




For
      the
      three months ended September 30, 2007, including the Carolina Transformer site,
      the Ward Transformer site and MGP sites discussed below, PEC made no material
      accruals or expenditures. For the nine months ended September 30, 2007,
      including the Carolina Transformer site, the Ward Transformer site and MGP
      sites
      discussed below, PEC reduced its accrual by approximately $4 million, primarily
      related to the Ward Transformer site, and spent approximately $2 million. For
      the three months ended September 30, 2006, PEC made no additional accruals
      and
      spent approximately $1 million. For the nine months ended September 30, 2006,
      PEC accrued approximately $21 million, of which approximately $9 million related
      to the Ward Transformer site and approximately $12 million related to MGP sites,
      and spent approximately $5 million. For the nine months ended September 30,
      2007, PEC received $2 million in insurance proceeds. In October 2006, PEC
      received orders from the NCUC and SCPSC to defer and amortize certain
      environmental remediation expenses, net of insurance proceeds (See Note
      4A).




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




During
      the fourth quarter of 2004, the EPA advised PEC that it had been identified
      as a
      PRP at the Ward Transformer site located in Raleigh, N.C. The EPA offered PEC
      and a number of other PRPs the opportunity to negotiate cleanup of the site
      and
      reimbursement to the EPA for the EPA’s past expenditures in addressing
      conditions at the site. Subsequently, PEC and other PRPs signed a settlement
      agreement, which requires the participating PRPs to remediate the site. At
      December 31, 2006, PEC’s accrual for its portion of the estimated remediation
      costs was approximately $9 million. In March 2007, the PRP agreement was amended
      to include an additional participating PRP, which reduced PEC’s allocable share.
      Accordingly, PEC refined and reduced its estimated liability for this site,
      as
      discussed above. At September 30, 2007, PEC’s recorded liability for the site
      was approximately $5 million. Actual experience may differ from current
      estimates, and it is probable that estimates will continue to change in the
      future. The outcome of this matter cannot be predicted.




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




In
      September 2005, the EPA advised PEC that it had been identified as a PRP at
      the
      Carolina Transformer site located in Fayetteville, N.C. The EPA offered PEC
      and
      a number of other PRPs the opportunity to share in the reimbursement to the
      EPA
      of past expenditures in addressing conditions at the site, which are currently
      approximately $33 million. Negotiations are continuing between the PRPs and
      the
      EPA in an effort to settle this matter. For the three and nine months ended
      September 30, 2007, PEC recorded an immaterial accrual based on its estimated
      share of the settlement offers made to date. An agreement with the EPA has
      not
      been finalized. The outcome of this matter cannot be predicted.




46


***PEF***




PEF
      has
      received approval from the FPSC for recovery of the majority of costs associated
      with the remediation of distribution and substation transformers through the
      Environmental Cost Recovery Clause (ECRC). Under agreements with the Florida
      Department of Environmental Protection, PEF is in the process of examining
      distribution transformer sites and substation sites for mineral oil-impacted
      soil remediation caused by equipment integrity issues. PEF has reviewed a number
      of distribution transformer sites and all substation sites. Based on changes
      to
      the estimated time frame for inspections of distribution transformer sites,
      PEF
      currently expects to have completed this review by the end of 2008. Should
      further sites be identified, PEF believes that any estimated costs would also
      be
      recovered through the ECRC. 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 approximately $5 million
      and $16 million, respectively, related to the remediation of transformers.
      For
      the three and nine months ended September 30, 2006, PEF accrued approximately
      $1
      million and $40 million, respectively, due to additional sites expected to
      require remediation and spent approximately $6 million and $12 million,
      respectively, related to the remediation of transformers. At September 30,
      2007,
      PEF has recorded a regulatory asset for the probable recovery of these costs
      through the ECRC.




The
      amounts for MGP and other sites, in the table above, relate to two former MGP
      sites and other sites associated with PEF that have required or are anticipated
      to require investigation and/or remediation. The amounts include approximately
      $12 million in insurance claim settlement proceeds received in 2004, which
      are
      restricted for use in addressing costs associated with environmental
      liabilities. For the three and nine months ended September 30, 2007 and 2006,
      PEF made no additional accruals or material expenditures.




**B.**
            **Air
                and Water Quality**




We
      are
      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 include the Clean Air Interstate Rule (CAIR), the Clean Air Mercury
      Rule (CAMR), the Clean Air Visibility Rule (CAVR), the NOx SIP Call Rule under
      Section 110 of the Clean Air Act (NOx SIP Call) and the Clean Smokestacks Act.
      At September 30, 2007, cumulative environmental compliance capital expenditures
      to date with regard to these environmental laws and regulations were $1.360
      billion, including $1.174 billion at PEC and $186 million at PEF.




As
      discussed in Note 4A, in June 2002, the Clean Smokestacks Act was enacted in
      North Carolina requiring the state's electric utilities to reduce the emissions
      of NOx and SO2
      from their North Carolina coal-fired power plants in phases by 2013. Two of
      PEC’s largest coal-fired generating units (the Roxboro No. 4 and Mayo Units)
      impacted by the Clean Smokestacks Act are jointly owned. Pursuant to joint
      ownership agreements, the joint owners are required to pay a portion of the
      costs of owning and operating these plants. PEC has determined that the most
      cost-effective Clean Smokestacks Act compliance strategy is to maximize the
      SO2removal
      from its larger coal-fired units, including Roxboro No. 4 and Mayo, so as to
      avoid the installation of expensive emission controls on its smaller coal-fired
      units. In order to address the joint owner's concerns that such a compliance
      strategy would result in a disproportionate share of the cost of compliance
      for
      the jointly owned units, PEC entered into an agreement with the joint owner
      to
      limit its aggregate costs associated with capital expenditures to comply with
      the Clean Smokestacks Act to approximately $38 million. PEC recorded a related
      liability for the joint owner's share of estimated costs in excess of the
      contract amount. At September 30, 2007, and December 31, 2006, the amount of
      the
      liability was $30 million and $29 million, respectively, based upon the
      respective current estimates for Clean Smokestacks Act compliance. 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. In 2006, PEC
      notified the NCUC of its intent to record these estimated excess costs as part
      of the $569 million amortization required to be recorded by December 31, 2007,
      and accordingly, recorded the indemnification expense to Clean Smokestacks
      Act
      amortization. If the settlement agreement filed on October 22, 2007 (See Note
      4A) is approved by the NCUC, under its provisions any costs in excess of the
      joint owner’s share will be treated in the same manner as PEC’s Clean
      Smokestacks costs in excess of the original estimated compliance
      costs.




47


**13.**
            **COMMITMENTS
                AND CONTINGENCIES**




Contingencies
      and significant changes to the commitments discussed in Note 22 in the 2006
      Form
      10-K are described below.




**A.**
            **Purchase
                Obligations**




***Progress
      Energy***




As
      part
      of our ordinary course of business, we enter into various long- and short-term
      contracts for fuel requirements at our generating plants. Through September
      30,
      2007, contracts procured through our subsidiaries have increased our aggregate
      purchase obligations for fuel and purchased power by $ 4.274 billion from
      $13.133 billion, as stated in Note 22A in the 2006 Form 10-K. Future obligations
      under operating leases also increased by approximately $413 million from $428
      million at December 31, 2006. These increases are discussed under “PEC” and
“PEF” below.




***PEC***




Through
      September 30, 2007, PEC’s fuel and purchase power commitments increased by
      $1.015 billion from $4.358 billion, as stated in Note 22A in the 2006 Form
      10-K.
      This increase is primarily related to nuclear fuel commitments, of which
      approximately $412 million will be incurred through 2011, with the remainder
      incurred through 2018.




***PEF***




Through
      September 30, 2007, PEF’s fuel and purchase power commitments increased by
      $3.494 billion from $8.513 billion as stated in Note 22A in the 2006 Form 10-K.
      The increase is primarily due to precedent and related agreements PEF entered
      into on December 2, 2004, for the supply of natural gas and associated firm
      pipeline transportation to augment PEF’s gas supply needs for the period from
      May 1, 2007, to April 30, 2027, as discussed in Note 22A in the 2006 Form 10-K.
      At September 30, 2007, the total cost associated with these agreements is
      approximately $4.4 billion, an increase of $500 million from December 31, 2006,
      as payments under the gas supply agreement are based on a market index, which
      has increased since year-end. Based upon current market prices, we anticipate
      incurring these costs ratably over the contract period. The transactions were
      subject to several conditions precedent, some of which were satisfied at
      December 31, 2006. Due to the conditions in the agreements, the estimated costs
      associated with these agreements were not included in our or PEF’s contractual
      cash obligations table at December 31, 2006. During 2007, the remaining
      conditions precedent were satisfied and the long-term contracts were contractual
      obligations of PEF at September 30, 2007.




In
      August
      2007, PEF entered into a purchased power agreement, which is classified as
      an
      operating lease. The agreement calls for minimum annual payments of
      approximately $28 million from 2012 through 2027 for a total of approximately
      $420 million.




**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, 2007, 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, 2007, 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,
      and for timely payment of obligations in support of our nonwholly owned
      synthetic fuels operations, which are within the scope of FIN 45. Related to
      the
      sales of businesses, the latest notice period extends until 2012 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




48


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, 2007, the estimated maximum exposure for guarantees and
      indemnifications for which a maximum exposure is determinable was $427 million,
      including $32 million at PEF. At September 30, 2007, and December 31, 2006,
      we
      have recorded liabilities related to guarantees and indemnifications to third
      parties of approximately $80 million and $60 million, respectively. These
      amounts include $30 million and $29 million, respectively, for PEC and $8
      million for PEF at September 30, 2007, and December 31, 2006. As current
      estimates change, it is possible that additional losses related to guarantees
      and indemnifications to third parties, which could be material, may be recorded
      in the future.




In
      addition, the Parent has issued $300 million 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. Our damages due to the DOE’s
      breach will be significant, but have yet to be determined. Approximately 60
      cases involving the government’s actions in connection with spent nuclear fuel
      are currently pending in the Court of Federal Claims.




The
      DOE
      and the Utilities agreed to, and the trial court entered, a stay of proceedings,
      in order to allow for possible efficiencies due to the resolution of legal
      and
      factual issues in previously filed cases in which similar claims are being
      pursued by other plaintiffs. These issues may include, among others, so-called
      “rate issues,” or the minimum mandatory schedule for the acceptance of spent
      nuclear fuel and high-level radioactive waste by which the government was
      contractually obligated to accept contract holders’ spent nuclear fuel and/or
      high-level waste, and issues regarding recovery of damages under a partial
      breach of contract theory that will be alleged to occur in the future. These
      issues have been or are expected to be presented in the trials or appeals that
      occurred in 2006 or are currently scheduled to occur during 2007. Resolution
      of
      these issues in other cases could facilitate agreements by the parties in the
      Utilities’ lawsuit, or at a minimum, inform the court of decisions reached by
      other courts if they remain contested and require resolution in this case.
      In
      July 2005, the parties jointly requested a continuance of the stay through
      December 15, 2005, which the trial court granted. Subsequently, the trial court
      continued the stay until March 17, 2006. The trial court lifted the stay on
      March 22, 2006, and discovery has commenced. The trial court issued a scheduling
      order on March 23, 2006, and the case is scheduled to go to trial on November
      5,
      2007.




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 U.S. Court of Appeals for the District
      of Columbia Circuit (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 D.C. Court of Appeals
      rejected the challenge to the constitutionality of the resolution approving
      Yucca Mountain, but ruled that the EPA was wrong to set a 10,000-year compliance
      period in the radiation protection standard. In August 2005, the EPA issued
      new
      proposed standards. The proposed standards include a 1,000,000-year compliance
      period in the radiation protection standard. Comments were due November 21,
      2005, and are being reviewed by the EPA. The EPA is expected to issue a new
      safety standard for the repository later this year. The DOE originally planned
      to submit a license application to the NRC to construct the Yucca Mountain
      facility by the end of 2004. However, in November 2004, the DOE announced it
      would not submit the license application until mid-2005 or later. The DOE did
      not submit the license application in 2005 and has since reported that the
      license application will be submitted by June 2008 if full funding is obtained
      for fiscal year 2008. The DOE requested $545 million for fiscal year 2007 and
      received $445 million.




49


The
      DOE
      has requested $495 million for fiscal year 2008. The budget for fiscal year
      2008
      has not been finalized but the Senate Appropriations Committee has recommended
      funding of $446 million. 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. Based upon this
      certification, the DOE is expected to submit its license application in spring
      2008. 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 stated that if legislative changes
      requested by the Bush administration are enacted, the repository may be able
      to
      accept spent nuclear fuel starting in 2017, but 2020 is more probable due to
      anticipated litigation by the state of Nevada. The Utilities cannot predict
      the
      outcome of this matter.




With
      certain modifications and additional approvals by the NRC, including the
      installation of onsite dry cask storage facilities at Robinson, Brunswick 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. 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 Earthco synthetic fuels facilities (Earthco); certain
      affiliates of Earthco; EFC Synfuel LLC (which is owned indirectly by Progress
      Energy, Inc.) and certain of its affiliates, including Solid Energy LLC; Solid
      Fuel LLC; Ceredo Synfuel LLC; Gulf Coast Synfuel LLC (currently named Sandy
      River Synfuel LLC) (collectively, the Progress Affiliates), as amended by an
      amendment to Purchase Agreement as of August 23, 2000 (the Asset Purchase
      Agreement). Global has asserted (1) that pursuant to the Asset Purchase
      Agreement, it is entitled to an interest in two synthetic fuels facilities
      currently owned by the Progress Affiliates and an option to purchase additional
      interests in the two synthetic fuels facilities, (2) that it is entitled to
      damages because the Progress Affiliates prohibited it from procuring purchasers
      for the synthetic fuels facilities and (3) a number of tort claims related
      to
      the contracts.




The
      first
      suit, U.S. Global, LLC v. Progress Energy, Inc. et al., asserts the above claims
      in a case filed in the Circuit Court for Broward County, Fla., in March 2003
      (the Florida Global Case), 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, 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 (the North Carolina Global Case). 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. The remainder of the suit continues. We cannot predict
      the outcome of this matter.




50


**OTHER
      LITIGATION MATTERS**




We
      and
      our subsidiaries are involved in various litigation matters in the ordinary
      course of business, some of which involve substantial amounts. Where
      appropriate, we have made accruals and disclosures in accordance with SFAS
      No.
      5, “Accounting for Contingencies,” to provide for such matters. In the opinion
      of management, the final disposition of pending litigation would not have a
      material adverse effect on our consolidated results of operations or financial
      position.




**14.**
            **CONDENSED
                CONSOLIDATING
                STATEMENTS**




As
      discussed in Note 23 in the 2006 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 Corporation (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
      2006
      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. The Other column
      includes the consolidated financial results of all other non-guarantor
      subsidiaries and elimination entries for all intercompany transactions. 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 CCO as
      discontinued operations as described in Note 3.


51





Condensed
                Consolidating Statement of Income
              Three
                Months Ended September 30, 2007*(in
                millions)*
            
            **Parent**
            
            
            **Subsidiary
                Guarantor**
            
            
            **Other**
            
            
            **Progress
                Energy, Inc.****Operating
                revenues**Electric
            
            $
            −
            
            
            $
            1,455
            
            
            $
            1,286
            
            
            $
            2,741Diversified
                business
            
            
            −
            
            
            
            310
            
            
            
            49
            
            
            
            359**Total
                operating revenues**
            
            
            −
            
            
            
            1,765
            
            
            
            1,335
            
            
            
            3,100**Operating
                expenses**UtilityFuel
                used in electric generation
            
            
            −
            
            
            
            544
            
            
            
            385
            
            
            
            929Purchased
                power
            
            
            −
            
            
            
            281
            
            
            
            109
            
            
            
            390Operation
                and maintenance
            
            
            2
            
            
            
            213
            
            
            
            241
            
            
            
            456Depreciation
                and amortization
            
            
            −
            
            
            
            100
            
            
            
            121
            
            
            
            221Taxes
                other than on income
            
            
            −
            
            
            
            83
            
            
            
            52
            
            
            
            135Diversified
                businessCost
                of sales
            
            
            −
            
            
            
            284
            
            
            
            45
            
            
            
            329Depreciation
                and amortization
            
            
            −
            
            
            
            2
            
            
            
            −
            
            
            
            2Other
            
            
            −
            
            
            
            8
            
            
            
            3
            
            
            
            11**Total
                operating expenses**
            
            
            2
            
            
            
            1,515
            
            
            
            956
            
            
            
            2,473**Operating
                (loss) income**
            
            
            (2
            )
            
            
            250
            
            
            
            379
            
            
            
            627Other
                income (expense), net
            
            
            10
            
            
            
            13
            
            
            
            (9
            )
            
            
            14Interest
                charges, net
            
            
            51
            
            
            
            53
            
            
            
            50
            
            
            
            154**(Loss)
                income from continuing operations before income tax, equity in earnings
                of
                consolidated subsidiaries and minority interest**
            
            
            (43
            )
            
            
            210
            
            
            
            320
            
            
            
            487**Income
                tax (benefit) expense**
            
            
            (20
            )
            
            
            58
            
            
            
            116
            
            
            
            154**Equity
                in earnings of consolidated subsidiaries**
            
            
            340
            
            
            
            −
            
            
            
            (340
            )
            
            
            −**Minority
                interest in subsidiaries’ income, net of tax**
            
            
            −
            
            
            
            (14)
            
            
            
            −
            
            
            
            (14)**Income
                (loss) from continuing operations**
            
            
            317
            
            
            
            138
            
            
            
            (136
            )
            
            
            319**Discontinued
                operations, net of tax**
            
            
            2
            
            
            
            1
            
            
            
            (3
            )
            
            
            −**Net
                income (loss)**
            
            $
            319
            
            
            $
            139
            
            
            $
            (139
            )
            
            $
            319





52





Condensed
                Consolidating Statement of Income
              Three
                Months Ended September 30, 2006*(in
                millions)*
            
            **Parent**
            
            
            **Subsidiary
                Guarantor**
            
            
            **Other**
            
            
            **Progress
                Energy, Inc.****Operating
                revenues**Electric
            
            $
            −
            
            
            $
            1,399
            
            
            $
            1,200
            
            
            $
            2,599Diversified
                business
            
            
            −
            
            
            
            175
            
            
            
            2
            
            
            
            177**Total
                operating revenues**
            
            
            −
            
            
            
            1,574
            
            
            
            1,202
            
            
            
            2,776**Operating
                expenses**UtilityFuel
                used in electric generation
            
            
            −
            
            
            
            538
            
            
            
            322
            
            
            
            860Purchased
                power
            
            
            −
            
            
            
            256
            
            
            
            135
            
            
            
            391Operation
                and maintenance
            
            
            3
            
            
            
            171
            
            
            
            209
            
            
            
            383Depreciation
                and amortization
            
            
            −
            
            
            
            108
            
            
            
            135
            
            
            
            243Taxes
                other than on income
            
            
            −
            
            
            
            89
            
            
            
            52
            
            
            
            141Diversified
                businessCost
                of sales
            
            
            −
            
            
            
            187
            
            
            
            2
            
            
            
            189Depreciation
                and amortization
            
            
            −
            
            
            
            2
            
            
            
            −
            
            
            
            2Other
            
            
            −
            
            
            
            7
            
            
            
            3
            
            
            
            10**Total
                operating expenses**
            
            
            3
            
            
            
            1,358
            
            
            
            858
            
            
            
            2,219**Operating
                (loss) income**
            
            
            (3
            )
            
            
            216
            
            
            
            344
            
            
            
            557Other
                income (expense), net
            
            
            7
            
            
            
            9
            
            
            
            (12
            )
            
            
            4Interest
                charges, net
            
            
            70
            
            
            
            47
            
            
            
            31
            
            
            
            148**(Loss)
                income from continuing operations before income tax, equity in earnings
                of
                consolidated subsidiaries and minority interest**
            
            
            (66
            )
            
            
            178
            
            
            
            301
            
            
            
            413**Income
                tax (benefit) expense**
            
            
            (14
            )
            
            
            60
            
            
            
            87
            
            
            
            133**Equity
                in earnings of consolidated subsidiaries**
            
            
            371
            
            
            
            −
            
            
            
            (371
            )
            
            
            −**Minority
                interest in subsidiaries’ loss, net of tax**
            
            
            −
            
            
            
            3
            
            
            
            −
            
            
            
            3**Income
                (loss) from continuing operations**
            
            
            319
            
            
            
            121
            
            
            
            (157
            )
            
            
            283**Discontinued
                operations, net of tax**
            
            
            −
            
            
            
            59
            
            
            
            (23
            )
            
            
            36**Net
                income (loss)**
            
            $
            319
            
            
            $
            180
            
            
            $
            (180
            )
            
            $
            319





53





Condensed
                Consolidating Statement of Income
              Nine
                Months Ended September 30, 2007*(in
                millions)*
            
            **Parent**
            
            
            **Subsidiary
                Guarantor**
            
            
            **Other**
            
            
            **Progress
                Energy, Inc.****Operating
                revenues**Electric
            
            $
            −
            
            
            $
            3,595
            
            
            $
            3,339
            
            
            $
            6,934Diversified
                business
            
            
            −
            
            
            
            812
            
            
            
            94
            
            
            
            906**Total
                operating revenues**
            
            
            −
            
            
            
            4,407
            
            
            
            3,433
            
            
            
            7,840**Operating
                expenses**UtilityFuel
                used in electric generation
            
            
            −
            
            
            
            1,340
            
            
            
            1,041
            
            
            
            2,381Purchased
                power
            
            
            −
            
            
            
            651
            
            
            
            243
            
            
            
            894Operation
                and maintenance
            
            
            9
            
            
            
            586
            
            
            
            742
            
            
            
            1,337Depreciation
                and amortization
            
            
            −
            
            
            
            297
            
            
            
            365
            
            
            
            662Taxes
                other than on income
            
            
            −
            
            
            
            233
            
            
            
            151
            
            
            
            384Other
            
            
            −
            
            
            
            12
            
            
            
            2
            
            
            
            14Diversified
                businessCost
                of sales
            
            
            −
            
            
            
            812
            
            
            
            114
            
            
            
            926Depreciation
                and amortization
            
            
            −
            
            
            
            6
            
            
            
            −
            
            
            
            6Gain
                on the sale of assets
            
            
            −
            
            
            
            (17
            )
            
            
            −
            
            
            
            (17
            )Other
            
            
            −
            
            
            
            30
            
            
            
            8
            
            
            
            38**Total
                operating expenses**
            
            
            9
            
            
            
            3,950
            
            
            
            2,666
            
            
            
            6,625**Operating
                (loss) income**
            
            
            (9
            )
            
            
            457
            
            
            
            767
            
            
            
            1,215Other
                income, net
            
            
            19
            
            
            
            34
            
            
            
            1
            
            
            
            54Interest
                charges, net
            
            
            150
            
            
            
            137
            
            
            
            145
            
            
            
            432**(Loss)
                income from continuing operations before income tax, equity in earnings
                of
                consolidated subsidiaries and minority interest**
            
            
            (140
            )
            
            
            354
            
            
            
            623
            
            
            
            837**Income
                tax (benefit) expense**
            
            
            (63
            )
            
            
            51
            
            
            
            187
            
            
            
            175**Equity
                in earnings of consolidated subsidiaries**
            
            
            472
            
            
            
            −
            
            
            
            (472
            )
            
            
            −**Minority
                interest in subsidiaries’ loss, net of tax**
            
            
            −
            
            
            
            8
            
            
            
            −
            
            
            
            8**Income
                (loss) from continuing operations**
            
            
            395
            
            
            
            311
            
            
            
            (36
            )
            
            
            670**Discontinued
                operations, net of tax**
            
            
            6
            
            
            
            (7
            )
            
            
            (268
            )
            
            
            (269
            )**Net
                income (loss)**
            
            $
            401
            
            
            $
            304
            
            
            $
            (304
            )
            
            $
            401





54





Condensed
                Consolidating Statement of Income
              Nine
                Months Ended September 30, 2006*(in
                millions)*
            
            **Parent**
            
            
            **Subsidiary
                Guarantor**
            
            
            **Other**
            
            
            **Progress
                Energy, Inc.****Operating
                revenues**Electric
            
            $
            −
            
            
            $
            3,553
            
            
            $
            3,113
            
            
            $
            6,666Diversified
                business
            
            
            −
            
            
            
            628
            
            
            
            3
            
            
            
            631**Total
                operating revenues**
            
            
            −
            
            
            
            4,181
            
            
            
            3,116
            
            
            
            7,297**Operating
                expenses**UtilityFuel
                used in electric generation
            
            
            −
            
            
            
            1,379
            
            
            
            880
            
            
            
            2,259Purchased
                power
            
            
            −
            
            
            
            601
            
            
            
            279
            
            
            
            880Operation
                and maintenance
            
            
            10
            
            
            
            515
            
            
            
            691
            
            
            
            1,216Depreciation
                and amortization
            
            
            −
            
            
            
            301
            
            
            
            404
            
            
            
            705Taxes
                other than on income
            
            
            −
            
            
            
            238
            
            
            
            142
            
            
            
            380Other
            
            
            −
            
            
            
            (2
            )
            
            
            −
            
            
            
            (2
            )Diversified
                businessCost
                of sales
            
            
            −
            
            
            
            645
            
            
            
            27
            
            
            
            672Depreciation
                and amortization
            
            
            −
            
            
            
            11
            
            
            
            10
            
            
            
            21Impairment
                of assets
            
            
            −
            
            
            
            44
            
            
            
            47
            
            
            
            91Other
            
            
            −
            
            
            
            27
            
            
            
            13
            
            
            
            40**Total
                operating expenses**
            
            
            10
            
            
            
            3,759
            
            
            
            2,493
            
            
            
            6,262**Operating
                (loss) income**
            
            
            (10
            )
            
            
            422
            
            
            
            623
            
            
            
            1,035Other
                income (expense), net
            
            
            9
            
            
            
            47
            
            
            
            (20
            )
            
            
            36Interest
                charges, net
            
            
            216
            
            
            
            142
            
            
            
            111
            
            
            
            469**(Loss)
                income from continuing operations before income tax, equity in earnings
                of
                consolidated subsidiaries and minority interest**
            
            
            (217
            )
            
            
            327
            
            
            
            492
            
            
            
            602**Income
                tax (benefit) expense**
            
            
            (73
            )
            
            
            107
            
            
            
            171
            
            
            
            205**Equity
                in earnings of consolidated subsidiaries**
            
            
            461
            
            
            
            −
            
            
            
            (461
            )
            
            
            −**Minority
                interest in subsidiaries’ income, net of tax**
            
            
            −
            
            
            
            (10)
            
            
            
            −
            
            
            
            (10)**Income
                (loss) from continuing operations**
            
            
            317
            
            
            
            210
            
            
            
            (140
            )
            
            
            387**Discontinued
                operations, net of tax**
            
            
            −
            
            
            
            86
            
            
            
            (156
            )
            
            
            (70
            )**Net
                income (loss)**
            
            $
            317
            
            
            $
            296
            
            
            $
            (296
            )
            
            $
            317





55





Condensed
                Consolidating Balance Sheet
              September
                30, 2007*(in
                millions)*
            
            **Parent**
            
            
            **Subsidiary
                Guarantor**
            
            
            **Other**
            
            
            **Progress
                Energy, Inc.****Utility
                plant, net**
            
            $
            −
            
            
            $
            7,198
            
            
            $
            8,990
            
            
            $
            16,188**Current
                assets**Cash
                and cash equivalents
            
            
            180
            
            
            
            341
            
            
            
            96
            
            
            
            617Short-term
                investments
            
            
            −
            
            
            
            178
            
            
            
            −
            
            
            
            178Notes
                receivable from affiliated companies
            
            
            321
            
            
            
            −
            
            
            
            (321
            )
            
            
            −Deferred
                fuel cost
            
            
            −
            
            
            
            9
            
            
            
            168
            
            
            
            177Assets
                of discontinued operations
            
            
            −
            
            
            
            27
            
            
            
            1
            
            
            
            28Other
                current assets
            
            
            95
            
            
            
            1,323
            
            
            
            1,126
            
            
            
            2,544**Total
                current assets**
            
            
            596
            
            
            
            1,878
            
            
            
            1,070
            
            
            
            3,544**Deferred
                debits and other assets**Investment
                in consolidated subsidiaries
            
            
            10,977
            
            
            
            −
            
            
            
            (10,977
            )
            
            
            −Goodwill
            
            
            −
            
            
            
            1
            
            
            
            3,654
            
            
            
            3,655Other
                assets and deferred debits
            
            
            142
            
            
            
            1,483
            
            
            
            1,561
            
            
            
            3,186**Total
                deferred debits and other assets**
            
            
            11,119
            
            
            
            1,484
            
            
            
            (5,762
            )
            
            
            6,841**Total
                assets**
            
            $
            11,715
            
            
            $
            10,560
            
            
            $
            4,298
            
            
            $
            26,573**Capitalization**Common
                stock equity
            
            $
            8,426
            
            
            $
            3,007
            
            
            $
            (3,007
            )
            
            $
            8,426Preferred
                stock of subsidiaries – not subject to mandatory
                redemption
            
            
            −
            
            
            
            34
            
            
            
            59
            
            
            
            93Minority
                interest
            
            
            −
            
            
            
            61
            
            
            
            3
            
            
            
            64Long-term
                debt, affiliate
            
            
            −
            
            
            
            309
            
            
            
            (38
            )
            
            
            271Long-term
                debt, net
            
            
            2,597
            
            
            
            3,137
            
            
            
            3,182
            
            
            
            8,916**Total
                capitalization**
            
            
            11,023
            
            
            
            6,548
            
            
            
            199
            
            
            
            17,770**Current
                liabilities**Current
                portion of long-term debt
            
            
            −
            
            
            
            164
            
            
            
            300
            
            
            
            464Short-term
                debt
            
            
            400
            
            
            
            −
            
            
            
            150
            
            
            
            550Notes
                payable to affiliated companies
            
            
            −
            
            
            
            313
            
            
            
            (313
            )
            
            
            −Liabilities
                of discontinued operations
            
            
            −
            
            
            
            12
            
            
            
            −
            
            
            
            12Other
                current liabilities
            
            
            246
            
            
            
            1,233
            
            
            
            712
            
            
            
            2,191**Total
                current liabilities**
            
            
            646
            
            
            
            1,722
            
            
            
            849
            
            
            
            3,217**Deferred
                credits and other liabilities**Noncurrent
                income tax liabilities
            
            
            −
            
            
            
            56
            
            
            
            229
            
            
            
            285Regulatory
                liabilities
            
            
            −
            
            
            
            1,160
            
            
            
            1,225
            
            
            
            2,385Accrued
                pension and other benefits
            
            
            12
            
            
            
            365
            
            
            
            519
            
            
            
            896Other
                liabilities and deferred credits
            
            
            34
            
            
            
            709
            
            
            
            1,277
            
            
            
            2,020**Total
                deferred credits and other liabilities**
            
            
            46
            
            
            
            2,290
            
            
            
            3,250
            
            
            
            5,586**Total
                capitalization and liabilities**
            
            $
            11,715
            
            
            $
            10,560
            
            
            $
            4,298
            
            
            $
            26,573





56





Condensed
                Consolidating Balance Sheet
              December
                31, 2006*(in
                millions)*
            
            **Parent**
            
            
            **Subsidiary
                Guarantor**
            
            
            **Other**
            
            
            **Progress
                Energy, Inc.****Utility
                plant, net**
            
            $
            −
            
            
            $
            6,337
            
            
            $
            8,908
            
            
            $
            15,245**Current
                assets**Cash
                and cash equivalents
            
            
            153
            
            
            
            40
            
            
            
            72
            
            
            
            265Short-term
                investments
            
            
            21
            
            
            
            −
            
            
            
            50
            
            
            
            71Notes
                receivable from affiliated companies
            
            
            58
            
            
            
            37
            
            
            
            (95
            )
            
            
            −Deferred
                fuel cost
            
            
            −
            
            
            
            −
            
            
            
            196
            
            
            
            196Assets
                of discontinued operations
            
            
            −
            
            
            
            45
            
            
            
            842
            
            
            
            887Other
                current assets
            
            
            27
            
            
            
            1,109
            
            
            
            1,030
            
            
            
            2,166**Total
                current assets**
            
            
            259
            
            
            
            1,231
            
            
            
            2,095
            
            
            
            3,585**Deferred
                debits and other assets**Investment
                in consolidated subsidiaries
            
            
            10,740
            
            
            
            −
            
            
            
            (10,740
            )
            
            
            −Goodwill
            
            
            −
            
            
            
            1
            
            
            
            3,654
            
            
            
            3,655Other
                assets and deferred debits
            
            
            126
            
            
            
            1,583
            
            
            
            1,507
            
            
            
            3,216**Total
                deferred debits and other assets**
            
            
            10,866
            
            
            
            1,584
            
            
            
            (5,579
            )
            
            
            6,871**Total
                assets**
            
            $
            11,125
            
            
            $
            9,152
            
            
            $
            5,424
            
            
            $
            25,701**Capitalization**Common
                stock equity
            
            $
            8,286
            
            
            $
            2,708
            
            
            $
            (2,708
            )
            
            $
            8,286Preferred
                stock of subsidiaries – not subject to mandatory
                redemption
            
            
            −
            
            
            
            34
            
            
            
            59
            
            
            
            93Minority
                interest
            
            
            −
            
            
            
            6
            
            
            
            4
            
            
            
            10Long-term
                debt, affiliate
            
            
            −
            
            
            
            309
            
            
            
            (38
            )
            
            
            271Long-term
                debt, net
            
            
            2,582
            
            
            
            2,512
            
            
            
            3,470
            
            
            
            8,564**Total
                capitalization**
            
            
            10,868
            
            
            
            5,569
            
            
            
            787
            
            
            
            17,224**Current
                liabilities**Current
                portion of long-term debt
            
            
            −
            
            
            
            124
            
            
            
            200
            
            
            
            324Notes
                payable to affiliated companies
            
            
            −
            
            
            
            77
            
            
            
            (77
            )
            
            
            −Liabilities
                of discontinued operations
            
            
            −
            
            
            
            13
            
            
            
            176
            
            
            
            189Other
                current liabilities
            
            
            210
            
            
            
            1,281
            
            
            
            814
            
            
            
            2,305**Total
                current liabilities**
            
            
            210
            
            
            
            1,495
            
            
            
            1,113
            
            
            
            2,818**Deferred
                credits and other liabilities**Noncurrent
                income tax liabilities
            
            
            −
            
            
            
            61
            
            
            
            245
            
            
            
            306Regulatory
                liabilities
            
            
            −
            
            
            
            1,091
            
            
            
            1,452
            
            
            
            2,543Accrued
                pension and other benefits
            
            
            14
            
            
            
            377
            
            
            
            566
            
            
            
            957Other
                liabilities and deferred credits
            
            
            33
            
            
            
            559
            
            
            
            1,261
            
            
            
            1,853**Total
                deferred credits and other liabilities**
            
            
            47
            
            
            
            2,088
            
            
            
            3,524
            
            
            
            5,659**Total
                capitalization and liabilities**
            
            $
            11,125
            
            
            $
            9,152
            
            
            $
            5,424
            
            
            $
            25,701





57





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
            
            
            $
            595
            
            
            $
            957**Investing
                activities**Gross
                utility property additions
            
            ****
            **−**
            
            
            
            (819
            )
            
            
            (585
            )
            
            
            (1,404
            )Nuclear
                fuel additions
            
            ****
            **−**
            
            
            
            (39
            )
            
            
            (159
            )
            
            
            (198
            )Proceeds
                from sales of discontinued operations and other assets, net of cash
                divested
            
            ****
            **−**
            
            
            
            38
            
            
            
            621
            
            
            
            659Purchases
                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 affiliates
            
            
            (250
            )
            
            
            37
            
            
            
            213
            
            
            ****
            **−**Return
                of investment in consolidated subsidiary
            
            
            190
            
            
            ****
            **−**
            
            
            
            (190
            )
            
            ****
            **−**Other
                investing activities
            
            
            (5
            )
            
            
            10
            
            
            
            6
            
            
            
            11**Net
                cash used by investing activities**
            
            
            (44
            )
            
            
            (951
            )
            
            
            (70
            )
            
            
            (1,065
            )**Financing
                activities**Issuance
                of common stock
            
            
            134
            
            
            ****
            **−**
            
            
            ****
            **−**
            
            
            
            134Proceeds
                from issuance of long-term debt, net
            
            ****
            **−**
            
            
            
            742
            
            
            ****
            **−**
            
            
            
            742Net
                increase in short-term debt
            
            
            400
            
            
            ****
            **−**
            
            
            
            150
            
            
            
            550Retirement
                of long-term debt
            
            ****
            **−**
            
            
            
            (87
            )
            
            
            (200
            )
            
            
            (287
            )Dividends
                paid on common stock
            
            
            (469
            )
            
            ****
            **−**
            
            
            ****
            **−**
            
            
            
            (469
            )Dividends
                paid to parent
            
            ****
            **−**
            
            
            
            (10
            )
            
            
            10
            
            
            ****
            **−**Changes
                in advances from affiliates
            
            ****
            **−**
            
            
            
            214
            
            
            
            (214
            )
            
            ****
            **−**Cash
                distributions to minority interests of consolidated
                subsidiary
            
            ****
            **−**
            
            
            
            (10
            )
            
            ****
            **−**
            
            
            
            (10
            )Other
                financing activities
            
            ****
            **−**
            
            
            
            49
            
            
            
            (27
            )
            
            
            22**Net
                cash provided (used) by financing activities**
            
            
            65
            
            
            
            898
            
            
            
            (281
            )
            
            
            682**Cash
                used by discontinued operations**Operating
                activities
            
            ****
            **−**
            
            
            
            (1
            )
            
            
            (219
            )
            
            
            (220
            )Investing
                activities
            
            ****
            **−**
            
            
            
            (1
            )
            
            
            (1
            )
            
            
            (2
            )**Net
                increase in cash and cash equivalents**
            
            
            27
            
            
            
            301
            
            
            
            24
            
            
            
            352**Cash
                and cash equivalents at beginning of period**
            
            
            153
            
            
            
            40
            
            
            
            72
            
            
            
            265**Cash
                and cash equivalents at end of period**
            
            $
            180
            
            
            $
            341
            
            
            $
            96
            
            
            $
            617





58





Condensed
                Consolidating Statement of Cash Flows
              Nine
                Months Ended September 30, 2006*(in
                millions)*
            
            **Parent**
            
            
            **Subsidiary
                Guarantor**
            
            
            **Other**
            
            
            **Progress
                Energy, Inc.****Net
                cash provided by operating activities**
            
            $
            376
            
            
            $
            728
            
            
            $
            405
            
            
            $
            1,509**Investing
                activities**Gross
                utility property additions
            
            
            −
            
            
            
            (519
            )
            
            
            (493
            )
            
            
            (1,012
            )Diversified
                business property additions
            
            
            −
            
            
            
            (1
            )
            
            
            −
            
            
            
            (1
            )Nuclear
                fuel additions
            
            
            −
            
            
            
            (6
            )
            
            
            (65
            )
            
            
            (71
            )Proceeds
                from sales of discontinued operations and other assets, net of cash
                divested
            
            
            −
            
            
            
            134
            
            
            
            414
            
            
            
            548Purchases
                of available-for-sale securities and other investments
            
            
            (392
            )
            
            
            (547
            )
            
            
            (748
            )
            
            
            (1,687
            )Proceeds
                from sales of available-for-sale securities and other
                investments
            
            
            191
            
            
            
            646
            
            
            
            774
            
            
            
            1,611Changes
                in advances to affiliates
            
            
            248
            
            
            
            (7
            )
            
            
            (241
            )
            
            
            −Return
                of investment in consolidated subsidiary
            
            
            287
            
            
            
            −
            
            
            
            (287
            )
            
            
            −Other
                investing activities
            
            
            (5
            )
            
            
            (3
            )
            
            
            (8
            )
            
            
            (16
            )**Net
                cash provided (used) by investing activities**
            
            
            329
            
            
            
            (303
            )
            
            
            (654
            )
            
            
            (628
            )**Financing
                activities**Issuance
                of common stock
            
            
            73
            
            
            
            −
            
            
            
            −
            
            
            
            73Proceeds
                from issuance of long-term debt, net
            
            
            397
            
            
            
            −
            
            
            
            −
            
            
            
            397Net
                decrease in short-term debt
            
            
            −
            
            
            
            (102
            )
            
            
            (73
            )
            
            
            (175
            )Retirement
                of long-term debt
            
            
            (801
            )
            
            
            (47
            )
            
            
            −
            
            
            
            (848
            )Dividends
                paid on common stock
            
            
            (454
            )
            
            
            −
            
            
            
            −
            
            
            
            (454
            )Dividends
                paid to parent
            
            
            −
            
            
            
            (222
            )
            
            
            222
            
            
            
            −Changes
                in advances from affiliates
            
            
            −
            
            
            
            (132
            )
            
            
            132
            
            
            
            −Cash
                distributions to minority interests of consolidated
                subsidiary
            
            
            −
            
            
            
            (74
            )
            
            
            −
            
            
            
            (74
            )Other
                financing activities
            
            
            (7
            )
            
            
            9
            
            
            
            (44
            )
            
            
            (42
            )**Net
                cash (used) provided by financing activities**
            
            
            (792
            )
            
            
            (568
            )
            
            
            237
            
            
            
            (1,123
            )**Cash
                provided (used) by discontinued operations**Operating
                activities
            
            
            −
            
            
            
            94
            
            
            
            21
            
            
            
            115Investing
                activities
            
            
            −
            
            
            
            (143
            )
            
            
            −
            
            
            
            (143
            )**Net
                (decrease) increase in cash and cash equivalents**
            
            
            (87
            )
            
            
            (192
            )
            
            
            9
            
            
            
            (270
            )**Cash
                and cash equivalents at beginning of period**
            
            
            239
            
            
            
            239
            
            
            
            127
            
            
            
            605**Cash
                and cash equivalents at end of period**
            
            $
            152
            
            
            $
            47
            
            
            $
            136
            
            
            $
            335





59


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 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, 2006 (2006 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 2006
      Form
      10-K.




***PROGRESS
      ENERGY***




**RESULTS
      OF OPERATIONS**




Our
      reportable operating business segments and their primary operations
      include:




·
            PEC
                – primarily engaged in the generation, transmission, distribution and
                sale
                of electricity in portions of North Carolina and South
                Carolina;


·
            PEF
                – primarily engaged in the generation, transmission, distribution and
                sale
                of electricity in portions of Florida;
                and


·
            Coal
                and Synthetic Fuels – primarily engaged in the production and sale of
                coal-based solid synthetic fuels in Kentucky and West Virginia, the
                operation of synthetic fuels facilities for third parties in West
                Virginia, and coal terminal services in Kentucky and West
                Virginia.





Our
      “Corporate and Other” segment is comprised of nonregulated businesses that do
      not separately meet the requirements as a business segment. It primarily
      includes the activities of the Parent and Progress Energy Service Company,
      LLC
      (PESC), as well as other nonregulated business areas.




As
      discussed in “Other Matters – Synthetic Fuels Tax Credits,” on September 14,
      2007, we idled production of synthetic fuels at our majority-owned synthetic
      fuels facilities. The decision to idle production was based on the current
      high
      level of oil prices and the resumption of synthetic fuels production was
      dependent upon a number of factors, including a reduction in oil prices. On
      October 12, 2007, based upon the continued high level of oil prices, unfavorable
      oil price projections through the end of 2007, and the expiration of the current
      synthetic fuels tax credit program at the end of 2007, we decided to permanently
      cease production of synthetic fuels at our majority-owned facilities. The
      operation of synthetic fuels facilities on behalf of third parties is expected
      to continue through December 31, 2007. Because we have abandoned our
      majority-owned facilities and our other synthetic fuels operations will cease
      as
      of December 31, 2007, we expect to report all of our synthetic fuels operations
      as discontinued operations in the fourth quarter of 2007.




60


As
      discussed more fully in Note 3 and “Results of Operations – Discontinued
      Operations,” many of our nonregulated business operations have recently been
      divested or are in the process of being divested. These operations have been
      classified as discontinued operations in the accompanying financial statements.
      The composition of our reportable operating business 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,
      2007, are compared to the same periods in 2006. The discussion begins with
      a
      summarized overview of our consolidated earnings, which is followed by a more
      detailed discussion and analysis by business segment.




**Overview**




For
      the
      quarter ended September 30, 2007, our net income was $319 million, or $1.24
      per
      share, compared to net income of $319 million, or $1.27 per share, for the
      same
      period in 2006. For the quarter ended September 30, 2007, our income from
      continuing operations was $319 million compared to $283 million for the same
      period in 2006. The increase in income from continuing operations as compared
      to
      prior year was primarily due to:




·
            higher
                tax credits due to higher synthetic fuels
                production;


·
            unrealized
                mark-to-market gains on Coal and Synthetic Fuels derivative
                contracts;


·
            favorable
                weather at the Utilities;


·
            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;


·
            lower
                Clean Smokestacks Act amortization expense at
                PEC;


·
            lower
                interest expense due to reducing holding company debt in late
                2006;


·
            lower
                income tax expense related to the deduction for domestic production
                activities; and


·
            higher
                wholesale sales at the Utilities.





Partially
      offsetting these items were:




·
            higher
                operating and maintenance expenses (O&M) at the
                Utilities;


·
            higher
                phase-out of year-to-date tax credits related to synthetic fuels
                production; and


·
            lower
                margins at Coal and Synthetic Fuels due to higher synthetic fuels
                production.





For
      the
      nine months ended September 30, 2007, our net income was $401 million, or $1.57
      per share, compared to net income of $317 million, or $1.27 per share, for
      the
      same period in 2006. For the nine months ended September 30, 2007, our income
      from continuing operations was $670 million compared to $387 million for the
      same period in 2006. The increase in income from continuing operations as
      compared to prior year was primarily due to:




·
            higher
                tax credits due to higher synthetic fuels
                production;


·
            impairment
                of our synthetic fuels assets and a portion of our coal terminal
                assets in
                2006;


·
            unrealized
                mark-to-market gains on Coal and Synthetic Fuels derivative
                contracts;


·
            lower
                interest expense due to reducing holding company debt in late
                2006;


·
            favorable
                weather at PEC;


·
            the
                impact of unrealized losses recorded on contingent value obligations
                (CVOs) during 2006;


·
            lower
                Clean Smokestacks Act amortization expense at
                PEC;


·
            lower
                income tax expense due to the closure of certain federal tax years
                and
                positions;


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


·
            higher
                wholesale sales at PEF; and


·
            favorable
                growth and usage at the Utilities.





61


Partially
      offsetting these items were:




·
            higher
                phase-out of tax credits related to synthetic fuels
                production;


·
            higher
                O&M expenses at the Utilities;


·
            the
                impact of the 2006 gain on sale of Level 3 Communications, Inc. (Level
                3)
                stock acquired as part of the divestiture of Progress Telecom, LLC
                (PT
                LLC); and


·
            higher
                other operating expenses due to disallowed fuel costs at
                PEF.





Our
      segments contributed the following profits or losses for the three and nine
      months ended September 30, 2007 and 2006:




Three
                Months Ended September 30,
            
            
            Nine
                Months Ended September 30,*(in
                millions)*
            
            **2007**
            
            
            2006
            
            
            **2007**
            
            
            2006Business
                SegmentPEC
            
            **$**
            **203**
            
            
            $
            188
            
            
            **$**
            **414**
            
            
            $
            349PEF
            
            ****
            **138**
            
            
            
            125
            
            
            ****
            **266**
            
            
            
            264Coal
                and Synthetic Fuels
            
            ****
            **(16**
            **)**
            
            
            7
            
            
            ****
            **56**
            
            
            
            (83
            )Total
                segment profit
            
            ****
            **325**
            
            
            
            320
            
            
            ****
            **736**
            
            
            
            530Corporate
                and Other
            
            ****
            **(6**
            **)**
            
            
            (37
            )
            
            ****
            **(66**
            **)**
            
            
            (143
            )Income
                from continuing operations
            
            ****
            **319**
            
            
            
            283
            
            
            ****
            **670**
            
            
            
            387Discontinued
                operations, net of tax
            
            ****
            **−**
            
            
            
            36
            
            
            ****
            **(269**
            **)**
            
            
            (70
            )Net
                income
            
            **$**
            **319**
            
            
            $
            319
            
            
            **$**
            **401**
            
            
            $
            317





**Progress
      Energy Carolinas**




PEC
      contributed segment profits of $203 million and $188 million for the three
      months ended September 30, 2007 and 2006, respectively. The increase in profits
      for the three months ended September 30, 2007, compared to the same period
      in
      2006, was primarily due to favorable weather, lower North Carolina Clean
      Smokestacks Act (Clean Smokestacks Act) amortization and higher wholesale sales,
      partially offset by higher O&M expenses related to plant outage and
      maintenance costs and employee benefit costs.




PEC
      contributed segment profits of $414 million and $349 million for the nine months
      ended September 30, 2007 and 2006, respectively. The increase in profits for
      the
      nine months ended September 30, 2007, compared to the same period in 2006,
      was
      primarily due to favorable weather, lower Clean Smokestacks Act amortization
      and
      favorable retail growth and usage, partially offset by higher O&M expenses
      related to plant outage and maintenance costs and employee benefit
      costs.




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 a presentation defined under GAAP, and it may not be comparable to other
      companies’ presentation nor more useful than the GAAP information provided
      elsewhere in this report.




62


Three
      Months ended September 30, 2007, Compared to Three Months ended September 30,
      2006




**REVENUES**




PEC’s
      revenues for the three months ended September 30, 2007 and 2006, and the amount
      and percentage change by customer class were as follows:




*(in
                millions)*
            
            Three
                Months Ended September 30,Customer
                Class
            
            **2007**
            
            
            Change
            
            
            %
                Change
            
            
            2006Residential
            
            **$**
            **503**
            
            
            $
            45
            
            
            
            9.8
            
            
            $
            458Commercial
            
            ****
            **325**
            
            
            
            28
            
            
            
            9.4
            
            
            
            297Industrial
            
            ****
            **196**
            
            
            
            (2
            )
            
            
            (1.0
            )
            
            
            198Governmental
            
            ****
            **29**
            
            
            
            1
            
            
            
            3.6
            
            
            
            28Total
                retail revenues
            
            ****
            **1,053**
            
            
            
            72
            
            
            
            7.3
            
            
            
            981Wholesale
            
            ****
            **208**
            
            
            
            3
            
            
            
            1.5
            
            
            
            205Unbilled
            
            ****
            **−**
            
            
            
            9
            
            
            
            −
            
            
            
            (9
            )Miscellaneous
            
            ****
            **25**
            
            
            
            2
            
            
            
            8.7
            
            
            
            23Total
                electric revenues
            
            ****
            **1,286**
            
            
            
            86
            
            
            
            7.2
            
            
            
            1,200Less:
                Fuel revenues
            
            ****
            **(441**
            **)**
            
            
            (49
            )
            
            
            −
            
            
            
            (392
            )Revenues
                excluding fuel
            
            **$**
            **845**
            
            
            $
            37
            
            
            
            4.6
            
            
            $
            808





PEC’s
      energy sales for the three months ended September 30, 2007 and 2006, and the
      amount and percentage change by customer class were as follows:




*(in
                millions of kWh)*
            Three
                Months Ended September 30,Customer
                Class
            **2007**
            Change
            %
                Change
            2006Residential
            **5,118**
            232
            4.7
            4,886Commercial
            **4,091**
            116
            2.9
            3,975Industrial
            **3,110**
            (207)
            (6.2)
            3,317Governmental
            **421**
            (6)
            (1.4)
            427Total
                retail energy sales
            **12,740**
            135
            1.1
            12,605Wholesale
            **4,184**
            210
            5.3
            3,974Unbilled
            **(138)**
            110
            −
            (248)Total
                kWh sales
            **16,786**
            455
            2.8
            16,331





PEC’s
      revenues, excluding fuel revenues of $441 million and $392 million for the
      three
      months ended September 30, 2007 and 2006, respectively, increased $37 million.
      The increase in revenues is primarily due to the $24 million favorable impact
      of
      weather with cooling degree days 15 percent higher than 2006. Additionally,
      wholesale revenues, excluding fuel revenues, increased $5 million due to higher
      wholesale sales and capacity revenues due to contract changes primarily with
      two
      major customers and the favorable impact of weather. Overall growth and usage
      did not have a material impact on revenues because favorable growth driven
      by an
      approximate increase in the average number of customers of 28,000 for the three
      months ended September 30, 2007, compared to the same period in 2006, was offset
      by lower average usage per customer.




Industrial
      electric energy revenues and sales decreased in 2007 compared to 2006 primarily
      due to continued reduction in textile manufacturing in North and South Carolina
      as a result of global competition and domestic consolidation as well as a
      downturn in the lumber and building materials segment as a result of declines
      in
      residential construction.




63


**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 $494 million for the three months ended September
      30, 2007, which represents a $37 million increase compared to the same period
      in
      2006. Fuel used in electric generation increased $63 million to $385 million
      compared to the prior year. This increase is due to a $39 million increase
      in
      fuel used in generation primarily due to higher system requirements and a change
      in generation mix as the percentage of generation supplied by natural gas
      increased in response to plant outages. A $24 million increase in deferred
      fuel
      expense primarily due to the collection of fuel costs from customers that had
      been previously under-recovered also contributed to the increase in fuel
      expense. Current year purchased power costs were $26 million lower than the
      three months ended September 30, 2006, due to lower cogeneration as a result
      of
      contract changes with one of PEC’s co-generators and decreased availability from
      a plant with which PEC has a tolling agreement.




**Operation
      and Maintenance**




O&M
      expenses were $246 million for the three months ended September 30, 2007, which
      represents a $28 million increase compared to the same period in 2006. O&M
      expenses increased $16 million primarily due to higher plant outage and
      maintenance costs and $11 million due to higher employee benefit
      costs.




**Depreciation
      and Amortization**




Depreciation
      and amortization expense was $118 million for the three months ended September
      30, 2007, which represents a $10 million decrease compared to the same period
      in
      2006. Depreciation and amortization expense decreased $14 million due to lower
      Clean Smokestacks Act amortization, partially offset by the impact of
      depreciable asset base increases.




**Total
      Other Income**




Total
      other income was $4 million for the three months ended September 30, 2007,
      compared to total other expense of $3 million for the same period in 2006.
      This change is primarily due to an $8 million increase in an
      indemnification liability recorded in the prior year for estimated capital
      costs
      associated with Clean Smokestacks Act compliance expected to be incurred in
      excess of the maximum billable costs to the joint owner (See Note
      12B).




**Total
      Interest Charges, net**




Total
      interest charges, net of $56 million increased $12 million for the three months
      ended September 30, 2007, compared to the same period in 2006, primarily due
      to
      the prior year reversal of $14 million of interest related to the favorable
      resolution of certain tax matters.




**Income
      Tax Expense**




Income
      tax expense increased $9 million for the three months ended September 30, 2007,
      as compared to the same period in 2006, primarily due to the $10 million tax
      impact of higher pre-tax earnings, partially offset by the $2 million impact
      related to the deduction for domestic production activities.




64


Nine
      Months ended September 30, 2007, Compared to Nine Months ended September 30,
      2006




**REVENUES**




PEC’s
      revenues for the nine months ended September 30, 2007 and 2006, and the amount
      and percentage change by customer class were as follows:




*(in
                millions)*
            
            Nine
                Months Ended September 30,Customer
                Class
            
            **2007**
            
            
            Change
            
            
            %
                Change
            
            
            2006Residential
            
            **$**
            **1,254**
            
            
            $
            121
            
            
            
            10.7
            
            
            $
            1,133Commercial
            
            ****
            **840**
            
            
            
            81
            
            
            
            10.7
            
            
            
            759Industrial
            
            ****
            **535**
            
            
            
            1
            
            
            
            0.2
            
            
            
            534Governmental
            
            ****
            **73**
            
            
            
            4
            
            
            
            5.8
            
            
            
            69Total
                retail revenues
            
            ****
            **2,702**
            
            
            
            207
            
            
            
            8.3
            
            
            
            2,495Wholesale
            
            ****
            **560**
            
            
            
            (4
            )
            
            
            (0.7
            )
            
            
            564Unbilled
            
            ****
            **3**
            
            
            
            24
            
            
            
            −
            
            
            
            (21
            )Miscellaneous
            
            ****
            **74**
            
            
            
            (1
            )
            
            
            (1.3
            )
            
            
            75Total
                electric revenues
            
            ****
            **3,339**
            
            
            
            226
            
            
            
            7.3
            
            
            
            3,113Less:
                Fuel revenues
            
            ****
            **(1,157**
            **)**
            
            
            (153
            )
            
            
            −
            
            
            
            (1,004
            )Revenues
                excluding fuel
            
            **$**
            **2,182**
            
            
            $
            73
            
            
            
            3.5
            
            
            $
            2,109





PEC’s
      energy sales for the nine months ended September 30, 2007 and 2006, and the
      amount and percentage change by customer class were as follows:




*(in
                millions of kWh)*
            Nine
                Months Ended September 30,Customer
                Class
            **2007**
            Change
            %
                Change
            2006Residential
            **13,434**
            693
            5.4
            12,741Commercial
            **10,682**
            437
            4.3
            10,245Industrial
            **8,917**
            (472)
            (5.0)
            9,389Governmental
            **1,080**
            −
            −
            1,080Total
                retail energy sales
            **34,113**
            658
            2.0
            33,455Wholesale
            **11,306**
            46
            0.4
            11,260Unbilled
            **(78)**
            317
            −
            (395)Total
                kWh sales
            **45,341**
            1,021
            2.3
            44,320





PEC’s
      revenues, excluding fuel revenues of $1.157 billion and $1.004 billion for
      the
      nine months ended September 30, 2007 and 2006, respectively, increased $73
      million. The increase in revenues is primarily due to favorable weather and
      favorable retail growth and usage. The impact of weather was $50 million
      favorable with heating degree days five percent higher than 2006 and cooling
      degree days 14 percent higher than 2006. Favorable retail growth and usage
      of
      $13 million was driven by an approximate increase in the average number of
      customers of 28,000 for the nine months ended September 30, 2007, compared
      to
      the same period in 2006, partially offset by a decrease in the average usage
      per
      retail customer.




Industrial
      electric energy sales decreased in 2007 compared to 2006 primarily due to
      continued reduction in textile manufacturing in the Carolinas as a result of
      global competition and domestic consolidation as well as a downturn in the
      lumber and building materials segment as a result of declines in residential
      construction. The increase in industrial revenues for 2007 compared to 2006
      is
      due to an increase in fuel revenues as a result of higher energy costs and
      the
      recovery of prior year fuel costs.




65


**EXPENSES**




**Fuel
      and Purchased Power**




Fuel
      and
      purchased power expenses were $1.284 billion for the nine months ended September
      30, 2007, which represents a $125 million increase compared to the same period
      in 2006. Fuel used in electric generation increased $161 million to $1.041
      billion compared to the prior year. This increase is due to a $112 million
      increase in fuel used in generation primarily due to higher system requirements
      and a change in generation mix as the percentage of generation supplied by
      natural gas increased in response to plant outages. A $49 million increase
      in
      deferred fuel expense primarily due to the collection of fuel costs from
      customers that had been previously under-recovered also contributed to the
      increase in fuel expense. Current year purchased power costs were $36 million
      lower than the nine months ended September 30, 2006, due to lower cogeneration
      as a result of contract changes with one of PEC’s co-generators.




**Operation
      and Maintenance**




O&M
      expenses were $762 million for the nine months ended September 30, 2007, which
      represents a $40 million increase compared to the same period in 2006. O&M
      expenses increased $35 million primarily due to higher plant outage and
      maintenance costs, $19 million due to higher employee benefit costs and $4
      million of higher costs related to the operation of emission control equipment
      installed at our coal-fired plants. This was partially offset by a decrease
      of
      $23 million primarily due to recording additional estimated environmental
      remediation expenses in 2006 (See Note 12A).




**Depreciation
      and Amortization**




Depreciation
      and amortization expense was $353 million for the nine months ended September
      30, 2007, which represents a $30 million decrease compared to the same period
      in
      2006. Depreciation and amortization expense decreased $40 million due to lower
      Clean Smokestacks Act amortization, partially offset by the impact of
      depreciable asset base increases.




**Taxes
      other than on Income**




Taxes
      other than on income were $151 million for the nine months ended September
      30,
      2007, which represents a $10 million increase compared to the same period in
      2006. The increase is primarily due to an $8 million increase in gross receipts
      taxes due to higher retail revenues. Gross receipts taxes are collected from
      customers and recorded as revenues and then remitted to the applicable taxing
      authority. Therefore, these taxes have no material impact on
      earnings.




**Total
      Other Income**




Total
      other income of $25 million increased $19 million for the nine months ended
      September 30, 2007, compared to the same period in 2006, primarily due to a
      $13
      million increase in an indemnification liability recorded in the prior year
      for
      estimated capital costs associated with Clean Smokestacks Act compliance
      expected to be incurred in excess of the maximum billable costs to the joint
      owner (See Note 12B). Additionally, AFUDC equity increased $5 million related
      to
      costs associated with certain large construction projects.




**Total
      Interest Charges, net**




Total
      interest charges, net of $165 million increased $8 million for the nine months
      ended September 30, 2007, compared to the same period in 2006, primarily due
      to
      the prior year reversal of $14 million of interest related to the favorable
      resolution of certain tax matters, partially offset by the current year reversal
      of $4 million of interest related to the closure of certain federal tax years
      and positions (See Note 7).




**Income
      Tax Expense**




Income
      tax expense increased $27 million for the nine months ended September 30, 2007,
      as compared to the same period in 2006, primarily due to the $37 million tax
      impact of higher pre-tax earnings. This was partially offset by




66


$5
      million of favorable current year changes related to prior year federal and
      state income tax returns and the $4 million impact related to the deduction
      for
      domestic production activities.




**Progress
      Energy Florida**




PEF
      contributed segment profits of $138 million and $125 million for the three
      months ended September 30, 2007 and 2006, respectively. The increase in profits
      for the three months ended September 30, 2007, compared to the same period
      in
      2006, was primarily due to lower income tax expense, favorable weather, lower
      property taxes and higher wholesale sales, partially offset by higher O&M
      expenses related to employee benefit costs and plant outage and maintenance
      costs and higher non-recovery clause depreciation and amortization
      expense.




PEF
      contributed segment profits of $266 million and $264 million for the nine months
      ended September 30, 2007 and 2006, respectively. The increase in profits for
      the
      nine months ended September 30, 2007, compared to the same period in 2006,
      was
      primarily due to lower income tax expense, higher wholesale sales and favorable
      AFUDC equity, partially offset by higher O&M expenses related to plant
      outage and maintenance costs and employee benefit costs, higher non-recovery
      clause depreciation and amortization expense and higher other operating
      expenses.




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 a presentation defined under GAAP, and
      it
      may not be comparable to other companies’ presentation nor more useful than the
      GAAP information provided elsewhere in this report.




Three
      Months ended September 30, 2007, Compared to Three Months ended September 30,
      2006




**REVENUES**




PEF’s
      revenues for the three months ended September 30, 2007 and 2006, and the amount
      and percentage change by customer class were as follows:




*(in
                millions)*
            
            Three
                Months Ended September 30,Customer
                Class
            
            **2007**
            
            
            Change
            
            
            %
                Change
            
            
            2006Residential
            
            **$**
            **774**
            
            
            $
            20
            
            
            
            2.7
            
            
            $
            754Commercial
            
            ****
            **336**
            
            
            
            2
            
            
            
            0.6
            
            
            
            334Industrial
            
            ****
            **84**
            
            
            
            (6
            )
            
            
            (6.7
            )
            
            
            90Governmental
            
            ****
            **84**
            
            
            
            1
            
            
            
            1.2
            
            
            
            83Total
                retail revenues
            
            ****
            **1,278**
            
            
            
            17
            
            
            
            1.3
            
            
            
            1,261Wholesale
            
            ****
            **133**
            
            
            
            35
            
            
            
            35.7
            
            
            
            98Unbilled
            
            ****
            **2**
            
            
            
            5
            
            
            
            −
            
            
            
            (3
            )Miscellaneous
            
            ****
            **43**
            
            
            
            −
            
            
            
            −
            
            
            
            43Total
                electric revenues
            
            ****
            **1,456**
            
            
            
            57
            
            
            
            4.1
            
            
            
            1,399Less:
                Fuel and other pass-through revenues
            
            ****
            **(966**
            **)**
            
            
            (41
            )
            
            
            −
            
            
            
            (925
            )Revenues
                excluding fuel and other pass-through revenues
            
            **$**
            **490**
            
            
            $
            16
            
            
            
            3.4
            
            
            $
            474





67


PEF’s
      electric energy sales for the three months ended September 30, 2007 and 2006,
      and the amount and percentage change by customer class are as
      follows:




*(in
                millions of kWh)*
            Three
                Months Ended September 30,Customer
                Class
            **2007**
            Change
            %
                Change
            2006Residential
            **6,490**
            121
            1.9
            6,369Commercial
            **3,555**
            74
            2.1
            3,481Industrial
            **1,008**
            (59)
            (5.5)
            1,067Governmental
            **927**
            22
            2.4
            905Total
                retail energy sales
            **11,980**
            158
            1.3
            11,822Wholesale
            **1,753**
            381
            27.8
            1,372Unbilled
            **(22)**
            75
            −
            (97)Total
                kWh sales
            **13,711**
            614
            4.7
            13,097





PEF’s
      revenues, excluding fuel and other pass-through revenues of $966 million and
      $925 million for the three months ended September 30, 2007 and 2006,
      respectively, increased $16 million. The increase in revenues is primarily
      due
      to the $11 million favorable impact of weather with cooling degree days six
      percent higher than 2006. Additionally, wholesale revenues, excluding fuel
      and
      other pass-through revenues, increased $7 million primarily due to higher sales
      and capacity revenues associated with contract changes with several major
      customers and the favorable impact of weather. Overall growth and usage did
      not
      have a material impact on revenues because favorable growth driven by an
      approximate average net increase in the number of customers of 22,000 for the
      three months ended September 30, 2007, compared to the same period in 2006
      was
      offset by lower average usage per customer.




Industrial
      electric energy revenues and sales decreased in 2007 compared to 2006 primarily
      due to a change in the terms of an agreement with a major customer.




**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 $825 million for the three months ended September
      30, 2007, which represents a $31 million increase compared to the same period
      in
      2006. Fuel used in electric generation increased $6 million to $544 million
      compared to the prior year. This increase is due to increased current year
      fuel
      costs of $109 million, partially offset by lower deferred fuel expense of $103
      million. The increase in current year fuel costs is primarily due to an increase
      in oil prices. Deferred fuel expenses were higher in 2006 primarily due to
      the
      collection of fuel costs from customers that had been previously
      under-recovered. Current year purchased power costs were $25 million higher
      than
      the three months ended September 30, 2006, due to increased current year
      purchases of $29 million as a result of higher capacity costs, primarily due
      to
      new contracts, and higher prices, partially offset by lower recovery of deferred
      capacity costs of $4 million.




**Operation
      and Maintenance**




O&M
      expenses were $213 million for the three months ended September 30, 2007, which
      represents a $42 million increase when compared to the same period in 2006.
      O&M expenses increased $17 million related to an increase in storm damage
      reserves from the one-year extension of the storm surcharge, which began August
      2007; $12 million related to higher environmental cost recovery (ECRC) and
      energy conservation cost recovery (ECCR) costs; $8 million due to higher
      employee benefit costs and $5 million due to higher plant outage and maintenance
      costs. The storm damage reserve, ECRC and ECCR expenses are recovered through
      cost-recovery clauses and, therefore, have no material impact on
      earnings.




68


**Depreciation
      and Amortization**




Depreciation
      and amortization expense was $100 million for the three months ended September
      30, 2007, which represents an $8 million decrease compared to the same period
      in
      2006. Depreciation and amortization expense decreased $16 million due to lower
      amortization of unrecovered storm restoration costs, partially offset by a
      $7
      million write-off of leasehold improvements, primarily related to vacated office
      space. Storm restoration costs, which were fully amortized in August 2007,
      were
      recovered through a cost-recovery clause and, therefore, have no material impact
      on earnings.




**Taxes
      other than on Income**




Taxes
      other than on income were $83 million for the three months ended September
      30,
      2007, which represents a $6 million decrease compared to the same period in
      2006. The decrease is primarily due to lower property taxes of $7 million as
      a
      result of lower property tax rates and decreased property value assessments
      in
      accordance with a state mandate.




**Total
      Other Income**




Total
      other income of $13 million increased $3 million for the three months ended
      September 30, 2007, compared to the same period in 2006, primarily due to a
      $6
      million increase in AFUDC equity related to costs associated with large
      construction projects, partially offset by lower interest income. Interest
      income decreased $3 million due primarily to lower interest on unrecovered
      storm
      restoration costs and lower short-term investment balances. We expect AFUDC
      equity to continue to increase for the remainder of 2007.




**Income
      Tax Expense**




Income
      tax expense decreased $15 million for the three months ended September 30,
      2007,
      compared to the same period in 2006, primarily due to the $6 million impact
      of
      tax levelization, discussed below, the $4 million impact of prior year
      unfavorable tax adjustments and the $3 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 tax rate
      to
      interim periods that is consistent with the estimated annual effective tax
      rate.
      PEF’s income tax expense was decreased by $4 million for the three months ended
      September 30, 2007 compared to an increase of $2 million for the three months
      ended September 30, 2006, 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 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.




69


Nine
      Months ended September 30, 2007, Compared to Nine Months ended September 30,
      2006




**REVENUES**




PEF’s
      revenues for the nine months ended September 30, 2007 and 2006, and the amount
      and percentage change by customer class were as follows:




*(in
                millions)*
            
            Nine
                Months Ended September 30,Customer
                Class
            
            **2007**
            
            
            Change
            
            
            %
                Change
            
            
            2006Residential
            
            **$**
            **1,798**
            
            
            $
            (22
            )
            
            
            (1.2
            )
            
            $
            1,820Commercial
            
            ****
            **864**
            
            
            
            (5
            )
            
            
            (0.6
            )
            
            
            869Industrial
            
            ****
            **236**
            
            
            
            (28
            )
            
            
            (10.6
            )
            
            
            264Governmental
            
            ****
            **225**
            
            
            
            2
            
            
            
            0.9
            
            
            
            223Retail
                revenue sharing
            
            ****
            **−**
            
            
            
            (1
            )
            
            
            (100.0
            )
            
            
            1Total
                retail revenues
            
            ****
            **3,123**
            
            
            
            (54
            )
            
            
            (1.7
            )
            
            
            3,177Wholesale
            
            ****
            **314**
            
            
            
            78
            
            
            
            33.1
            
            
            
            236Unbilled
            
            ****
            **29**
            
            
            
            8
            
            
            
            −
            
            
            
            21Miscellaneous
            
            ****
            **130**
            
            
            
            11
            
            
            
            9.2
            
            
            
            119Total
                electric revenues
            
            ****
            **3,596**
            
            
            
            43
            
            
            
            1.2
            
            
            
            3,553Less:
                Fuel and other pass-through revenues
            
            ****
            **(2,336**
            **)**
            
            
            (21
            )
            
            
            −
            
            
            
            (2,315
            )Revenues
                excluding fuel and other pass-through revenues
            
            **$**
            **1,260**
            
            
            $
            22
            
            
            
            1.8
            
            
            $
            1,238





PEF’s
      electric energy sales for the nine months ended September 30, 2007 and 2006,
      and
      the amount and percentage change by customer class were as follows:




*(in
                millions of kWh)*
            Nine
                Months Ended September 30,Customer
                Class
            **2007**
            Change
            %
                Change
            2006Residential
            **15,147**
            (278)
            (1.8)
            15,425Commercial
            **9,125**
            85
            0.9
            9,040Industrial
            **2,842**
            (331)
            (10.4)
            3,173Governmental
            **2,486**
            54
            2.2
            2,432Total
                retail energy sales
            **29,600**
            (470)
            (1.6)
            30,070Wholesale
            **4,370**
            1,028
            30.8
            3,342Unbilled
            **919**
            387
            −
            532Total
                kWh sales
            **34,889**
            945
            2.8
            33,944





PEF’s
      revenues, excluding fuel and other pass-through revenues of $2.336 billion
      and
      $2.315 billion for the nine months ended September 30, 2007 and 2006,
      respectively, increased $22 million. The increase in revenues is primarily
      due
      to increased wholesale revenues, other miscellaneous service revenues and
      favorable growth and usage, partially offset by unfavorable weather. Wholesale
      revenues, excluding fuel and other pass-through revenues, increased $20 million
      primarily due to the $18 million impact of increased capacity under contract
      with a major customer. Other miscellaneous service revenues increased primarily
      due to increased electric property rental revenues of $8 million. Favorable
      retail growth and usage of $6 million was driven by an approximate average
      net
      increase in the number of customers of 27,000 for the nine months ended
      September 30, 2007, compared to the same period in 2006, partially offset by
      lower average usage per customer. The impact of weather was $8 million
      unfavorable with cooling degree days two percent lower than 2006.




Industrial
      electric energy revenues and sales decreased in 2007 compared to 2006 primarily
      due to a change in the terms of an agreement with a major customer.




70


**EXPENSES**




**Fuel
      and Purchased Power**




Fuel
      and
      purchased power expenses were $1.991 billion for the nine months ended September
      30, 2007, which represents an $11 million increase compared to the same period
      in 2006. Fuel used in electric generation decreased $39 million to $1.340
      billion compared to the prior year. This decrease is due to lower deferred
      fuel
      expense of $206 million partially offset by increased current year fuel costs
      of
      $167 million. Deferred fuel expenses were higher in 2006 primarily due to the
      collection of fuel costs from customers that had been previously
      under-recovered. The increase in current year fuel costs is primarily due to
      an
      increase in oil and natural gas prices. Current year purchased power costs
      were
      $50 million higher than the nine months ended September 30, 2006, due to
      increased current year purchases of $64 million as a result of higher capacity
      costs, primarily due to new contracts, and higher prices, partially offset
      by
      lower recovery of deferred capacity costs of $14 million.




**Operation
      and Maintenance**




O&M
      expenses were $586 million for the nine months ended September 30, 2007, which
      represents a $71 million increase when compared to the same period in 2006.
      O&M expenses increased $27 million related to higher ECRC and ECCR costs,
      $17 million related to an increase in storm damage reserves from the one-year
      extension of the storm surcharge, which began August 2007; $14 million
      due to higher plant outage and maintenance costs; $9 million due to higher
      employee benefit costs and $4 million due to the estimated impact of additional
      Florida sales and use tax related to an ongoing audit in the current year.
      The
      ECRC, ECCR and storm damage reserve expenses are recovered through cost-recovery
      clauses and, therefore, have no material impact on earnings.




**Depreciation
      and Amortization**




Depreciation
      and amortization expense was $297 million for the nine months ended September
      31, 2007, which represents a $4 million decrease compared to the same period
      in
      2006. Depreciation and amortization expense decreased $18 million due to lower
      amortization of unrecovered storm restoration costs, partially offset by the
      impact of depreciable asset base increases and a $7 million write-off of
      leasehold improvements, primarily related to vacated office space. Storm
      restoration costs, which were fully amortized in August 2007, were recovered
      through a cost-recovery clause and, therefore, have no material impact on
      earnings.




**Other**




Other
      operating expenses of $12 million increased $14 million for the nine months
      ended September 30, 2007, compared to the same period in 2006, primarily due
      to
      the $12 million impact of a FPSC order requiring PEF to refund disallowed fuel
      costs to its ratepayers (See Note 4B).




**Total
      Other Income**




Total
      other income of $30 million increased $10 million for the nine months ended
      September 30, 2007, compared to the same period in 2006, primarily due to a
      $16
      million increase in AFUDC equity related to costs associated with large
      construction projects, partially offset by lower interest income. Interest
      income decreased $9 million due primarily to lower short-term investment
      balances and lower interest on unrecovered storm restoration costs. We expect
      AFUDC equity to continue to increase for the remainder of 2007.




**Income
      Tax Expense**




Income
      tax expense decreased $38 million for the nine months ended September 30, 2007,
      compared to the same period in 2006, primarily due to the $14 million tax impact
      of lower pre-tax earnings compared to the prior year, the $6 million impact
      of
      the increase in AFUDC equity discussed above, the $4 million impact related
      to
      the closure of certain federal tax years and positions (See Note 7), $5 million
      impact of tax levelization, discussed below, and the $4 million impact of prior
      year unfavorable tax adjustments. AFUDC equity is excluded from the calculation
      of income tax expense. GAAP requires companies to apply a levelized effective
      tax rate to interim periods that is consistent with the estimated annual
      effective tax rate. PEF’s income tax expense was decreased by $3 million for the
      nine months ended September 30, 2007 compared to an increase of $2 million
      for
      the nine months ended September 30, 2006, in order to maintain an effective
      tax
      rate consistent with the estimated annual rate. Fluctuations




71


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.




**Coal
      and Synthetic Fuels**




The
      operations of the Coal and Synthetic Fuels segment include the production and
      sale of coal-based solid synthetic fuels, the operation of synthetic fuels
      facilities for third parties, and coal terminal services. The following
      summarizes the Coal and Synthetic Fuels segment profits, which are reported
      within Diversified Business on the Consolidated Statements of
      Income:




Three
                Months Ended
              September
                30,
            
            
            Nine
                Months Ended
              September
                30,*(in
                millions)*
            
            **2007**
            
            
            2006
            
            
            **2007**
            
            
            2006Synthetic
                fuels operations
            
            **$**
            **(15**
            **)**
            
            $
            20
            
            
            **$**
            **73**
            
            
            $
            (59
            )Coal
                terminals and marketing
            
            ****
            **8**
            
            
            
            (6
            )
            
            ****
            **8**
            
            
            
            6Corporate
                overhead and other operations
            
            ****
            **(9**
            **)**
            
            
            (7
            )
            
            ****
            **(25**
            **)**
            
            
            (30
            )Segment
                (losses) profits
            
            **$**
            **(16**
            **)**
            
            $
            7
            
            
            **$**
            **56**
            
            
            $
            (83
            )





**SYNTHETIC
      FUELS OPERATIONS**




The
      production and sale of coal-based solid synthetic fuels generate operating
      losses, but qualify for tax credits under Section 29/45K of the Internal Revenue
      Code (the Code), which generally more than offset the effect of such losses
      (See
“Other Matters – Synthetic Fuels Tax Credits” below). Our synthetic fuels
      operations were as follows:




Three
                Months Ended September 30,
            
            
            Nine
                Months Ended September 30,*(in
                millions)*
            
            **2007**
            
            
            2006
            
            
            **2007**
            
            
            2006Tons
                sold
            
            ****
            **2.3**
            
            
            
            0.2
            
            
            ****
            **6.8**
            
            
            
            1.9After-tax
                losses (excluding impairment charge, valuation allowance and tax
                credits)
            
            **$**
            **(4**
            **)**
            
            $
            (2
            )
            
            **$**
            **(19**
            **)**
            
            $
            (52
            )After-tax
                impairment charge
            
            ****
            **−**
            
            
            
            −
            
            
            ****
            **−**
            
            
            
            (45
            )Net
                operating loss (NOL) valuation allowance
            
            ****
            **−**
            
            
            
            −
            
            
            ****
            **−**
            
            
            
            (7
            )Tax
                credits generated
            
            ****
            **67**
            
            
            
            6
            
            
            ****
            **200**
            
            
            
            54Tax
                credit inflation adjustment
            
            ****
            **−**
            
            
            
            −
            
            
            ****
            **2**
            
            
            
            10Tax
                credits reserve (increase) decrease due to estimated
                phase-out
            
            ****
            **(78**
            **)**
            
            
            16
            
            
            ****
            **(110**
            **)**
            
            
            (19
            )Net
                (loss) profit
            
            **$**
            **(15**
            **)**
            
            $
            20
            
            
            **$**
            **73**
            
            
            $
            (59
            )





Synthetic
      fuels operations had a net loss of $15 million for the three months ended
      September 30, 2007, compared to a net profit of $20 million for the same period
      in 2006. After-tax losses (excluding impairment charges, valuation allowance
      and
      tax credits) for synthetic fuels operations increased $2 million for the three
      months ended September 30, 2007, compared to the same period in 2006, primarily
      due to the impact of $32 million of lower after-tax margins as a result of
      higher coal-based solid synthetic fuels production, partially offset by the
      $31
      million unrealized after-tax mark-to-market gain recorded on derivative
      contracts entered into in January 2007 (See Note 9A). Tax credits recorded
      during the three months ended September 30, 2007, compared to the same period
      in
      2006, increased due to higher production. We increased production in 2007 as
      a
      result of shorter idling of synthetic fuels production in the current year
      compared to the prior year and the protection against oil price increases
      provided by the derivative contracts in the current year. The change in the
      tax
      credit reserve is primarily due to the increase in production and the change
      in
      the relative level of oil prices, which indicated an increase in estimated
      phase-out from 24 percent at June 30, 2007, to 55 percent at September 30,
      2007,
      compared to a decrease in estimated phase-out from 72 percent at June 30, 2006
      to 35 percent at September 30, 2006. Of the $78 million tax credit reserve
      increase during the three months ended September 30, 2007, $41 million relates
      to tax credits generated during the first six months of 2007. Similarly, of
      the
      $16 million tax credit reserve decrease during the three months ended
      September




72


30,
      2006,
      $18 million relates to tax credits generated during the first six months of
      2006. The 2007 tax credit reserve increase is due to the potential phase-out
      of
      the tax credits generated in 2007.




Synthetic
      fuels operations had a net profit of $73 million for the nine months ended
      September 30, 2007, compared to a net loss of $59 million for the same period
      in
      2006. After-tax losses (excluding impairment charges, valuation allowance and
      tax credits) for synthetic fuels operations decreased $33 million for the nine
      months ended September 30, 2007, compared to the same period in 2006, primarily
      due to the $45 million unrealized after-tax mark-to-market gain recorded on
      derivative contracts entered into in January 2007 (See Note 9A). After-tax
      losses (excluding impairment charges, valuation allowance and tax credits)
      were
      also positively impacted by lower depreciation expense due to the second quarter
      2006 impairment of our synthetic fuels assets and the $6 million after-tax
      impact of the recovery of losses from an equity investment. These were partially
      offset by $46 million of lower after-tax margins due to the increase in
      coal-based solid synthetic fuels production. Net profit for synthetic fuels
      operations increased in 2007 due to the $45 million after-tax impairment of
      synthetic fuels assets and the $7 million recognition of a valuation allowance
      recorded against the deferred tax assets for state NOL carry forwards, both
      of
      which were recorded in 2006. Tax credits recorded during the nine months ended
      September 30, 2007, compared to the same period in 2006, increased due to higher
      production. We increased production in 2007 as a result of shorter idling of
      synthetic fuels production in the current year compared to the prior year and
      the protection against oil price increases provided by the derivative contracts
      in the current year. The change in the tax credit reserve is primarily due
      to
      the increase in production and the change in the relative level of oil prices,
      which indicated a higher estimated phase-out in 2007 compared to 2006. The
      2007
      tax credit reserve increase includes $110 million due to the potential phase-out
      of the 2007 tax credits. The Department of the Treasury released the final
      2006
      inflation adjustment factor and the average wellhead price per barrel for
      unregulated domestic crude oil, which indicated a phase-out and devaluation
      of
      33 percent of the 2006 tax credits. This was 2 percent, or $2 million, lower
      than our December 31, 2006 phase-out estimate of 35 percent.




On
      September 14, 2007, we idled production of synthetic fuels at our majority-owned
      synthetic fuels facilities. The decision to idle production was based on the
      current high level of oil prices and the resumption of synthetic fuels
      production was dependent upon a number of factors, including a reduction in
      oil
      prices. On October 12, 2007, based upon the continued high level of oil prices,
      unfavorable oil price projections through the end of 2007, and the expiration
      of
      the current synthetic fuels tax credit program at the end of 2007, we decided
      to
      permanently cease production of synthetic fuels at our majority-owned
      facilities. The operation of synthetic fuels facilities on behalf of third
      parties is expected to continue through December 31, 2007. Because we have
      abandoned our majority-owned facilities and our other synthetic fuels operations
      will cease as of December 31, 2007, we expect to report all of our synthetic
      fuels operations as discontinued operations in the fourth quarter of 2007.
      See
“Other Matters – Synthetic Fuels Tax Credits” below for additional information
      on the impact of oil prices on Section 29/45K tax credits.




In
      March
      2007, we disposed of our 100 percent ownership interest in Ceredo Synfuel LLC
      (Ceredo) and entered into an agreement to operate Ceredo on behalf of the
      third-party buyer (see Note 3I and “Other Matters – Synthetic Fuels Tax
      Credits”). We have continued to consolidate Ceredo in accordance with Financial
      Accounting Standards Board Interpretation No. 46R, “Consolidation of Variable
      Interest Entities – An Interpretation of ARB No. 51” (FIN 46R), but we have
      recorded a 100 percent minority interest and there is no net earnings impact
      from Ceredo’s operations subsequent to the disposal. Consequently, tons sold,
      net operating results and tax credits recorded by Ceredo subsequent to March
      31,
      2007, are excluded from our Coal and Synthetic Fuels segment.




**COAL
      TERMINALS AND MARKETING**




Coal
      terminals and marketing (Coal) operations blend and transload coal as part
      of
      the trucking, rail and barge network for coal delivery. This business also
      has
      an operating fee agreement with our synthetic fuels operations for the procuring
      and processing of coal and the transloading and marketing of synthetic fuels.
      Coal operations had earnings of $8 million for the three months ended September
      30, 2007, compared to losses of $6 million for the same period in 2006. Coal’s
      2007 results increased due to the $24 million pre-tax increase in sales. As
      a
      result of the relationship with the synthetic fuels operations, fluctuations
      in
      Coal’s annual earnings are primarily related to production volumes at our
      synthetic fuels facilities. Because of the relationship with our synthetic
      fuels
      operations, which will cease in 2007, we expect to incur immaterial losses
      in
      the fourth quarter and we are currently evaluating alternative business
      strategies with respect to our Coal operations.




73


Coal
      operations had earnings of $8 million for the nine months ended September 30,
      2007, compared to earnings of $6 million for the same period in 2006. Coal’s
      2007 results increased primarily due to a $17 million pre-tax increase in sales
      and the $17 million pre-tax impairment of a portion of Coal’s terminal assets
      recorded in 2006, partially offset by the prior year impact of the $11 million
      pre-tax expense reduction due to restructuring a coal supply contract in 2006
      and the $10 million pre-tax expense due to a contract buyout for future coal
      purchases.




**CORPORATE
      OVERHEAD AND OTHER OPERATIONS**




Corporate
      overhead and other operations incurred losses of $9 million and $7 million
      for
      the three months ended September 30, 2007 and 2006, respectively, and $25
      million and $30 million for the nine months ended September 30, 2007 and 2006,
      respectively. The increase in losses for the three months ended September 30,
      2007, compared to the same period in 2006, is primarily due to higher interest
      expense driven by increased money pool borrowings to finance increased
      coal-based solid synthetic fuels production. The decrease in losses for the
      nine
      months ended September 30, 2007, compared to the same period in 2006, is
      primarily due to a decrease in the allocation of corporate overhead and lower
      interest expense resulting from the divestitures completed during
      2006.




**Corporate
      and Other**




The
      Corporate and Other segment consists of the operations of the Parent, PESC
      and
      other consolidating and non-operating entities (Corporate). Corporate and Other
      also includes other nonregulated business areas. Corporate and Other income
      (expense) is summarized below:




Three
                Months Ended September 30,
            
            
            Nine
                Months EndedSeptember
                30,*(in
                millions)*
            
            **2007**
            
            
            2006
            
            
            **2007**
            
            
            2006Other
                interest expense
            
            **$**
            **(50**
            **)**
            
            $
            (64
            )
            
            **$**
            **(136**
            **)**
            
            $
            (187
            )Contingent
                value obligations
            
            ****
            **1**
            
            
            
            (3
            )
            
            ****
            **(2**
            **)**
            
            
            (25
            )Tax
                levelization
            
            ****
            **21**
            
            
            
            15
            
            
            ****
            **(2**
            **)**
            
            
            (5
            )Other
                income tax benefit
            
            ****
            **24**
            
            
            
            16
            
            
            ****
            **78**
            
            
            
            58Other
            
            ****
            **(2**
            **)**
            
            
            (1
            )
            
            ****
            **(4**
            **)**
            
            
            16Corporate
                and Other after-tax expense
            
            **$**
            **(6**
            **)**
            
            $
            (37
            )
            
            **$**
            **(66**
            **)**
            
            $
            (143
            )





Other
      interest expense decreased $14 million for the three months ended September
      30,
      2007, and decreased $51 million for the nine months ended September 30, 2007,
      compared to the same periods in 2006. The decrease for the three months ended
      September 30, 2007, is primarily due to the $1.7 billion reduction in holding
      company debt during 2006, partially offset by a $14 million decrease in the
      interest allocated to discontinued operations. The decrease for the nine months
      ended September 30, 2007, is primarily due to the $1.7 billion reduction in
      holding company debt during 2006 and the impact of the closure of certain
      federal tax years and positions (See Note 7), partially offset by a $36 million
      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 2006 for operations that were sold
      later in 2006. Interest expense allocated to discontinued operations was less
      than $1 million and $14 million for the three months ended September 30, 2007
      and 2006, respectively. Interest expense allocated to discontinued operations
      was $12 million and $48 million for the nine months ended September 30, 2007
      and
      2006.




Progress
        Energy issued 98.6 million CVOs in connection with the acquisition of Florida
        Progress in 2000. Each CVO represents the right of the holder to receive
        contingent payments based on the performance of four synthetic fuels facilities
        owned by Progress Energy. The payments, if any, are based on the net after-tax
        cash flows the facilities generate. At September 30, 2007 and 2006, the CVOs
        had
        fair market values of approximately $34 million and $33 million, respectively.
        We recorded an unrealized gain of $1 million for the three months ended
        September 30, 2007, and unrealized losses of $3 million for the three months
        ended September 30, 2006, to record the changes in fair value of the CVOs,
        which
        had average unit prices of $0.35 and $0.33 at September 30, 2007 and 2006,
        respectively. We recorded unrealized losses of $2 million for the nine months
        ended September 30, 2007, and unrealized losses of $25 million for the nine
        months ended September 30, 2006.




74


GAAP
      requires companies to apply a levelized effective tax rate to interim periods
      that is consistent with the estimated annual effective tax rate. Income tax
      expense was decreased by $21 million for the three months ended September 30,
      2007, compared to a decrease of $15 million for the three months ended September
      30, 2006, and increased by $2 million for the nine months ended September 30,
      2007, compared to an increase of $5 million for the nine months ended September
      30, 2006, in order to maintain an effective rate consistent with the estimated
      annual rate. The tax credits associated with our synthetic fuels operations
      and
      seasonal fluctuations in our annual earnings primarily drive the fluctuations
      in
      the effective tax rate for interim periods. The tax levelization adjustment
      will
      vary each quarter, but it will have no effect on net income for the
      year.




Other
      income tax benefit increased for the three months ended September 30, 2007,
      compared to the same period in 2006, primarily due to the $5 million tax impact
      related to the deduction for domestic production activities. Other income tax
      benefit increased for the nine months ended September 30, 2007, compared to
      the
      same periods in 2006, primarily due to the $14 million impact related to the
      closure of certain federal tax years and positions (See Note 7) and other tax
      adjustments.




Other
      decreased $20 million for the nine months ended September 30, 2007, compared
      to
      the same period in 2006, primarily due to the $17 million gain, net of minority
      interest, on the sale of Level 3 stock subsequent to the sale of PT LLC in
      2006
      (See Note 3D).




**Discontinued
      Operations**




Over
      the
      last several years, we have reduced our business risk by exiting the majority
      of
      our nonregulated businesses. We divested, or announced divestitures, of multiple
      nonregulated businesses during 2007 and 2006 in accordance with our business
      strategy to reduce our business risk and to focus on the core operations of
      the
      Utilities. Consequently, we no longer report a Progress Ventures segment, and
      the composition of other continuing segments has been impacted by these
      divestitures.




**CCO
      OPERATIONS**




**CCO
      – Georgia Region**




On
      March
      9, 2007, our subsidiary, Progress 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 quarter
      ended March 31, 2007, we reversed $16 million after-tax of the impairment
      recorded in 2006. During each of the quarters ended June 30, 2007, and September
      30, 2007, we reversed an additional $1 million after-tax of the impairment
      as a
      result of closing adjustments.




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




CCO’s
      operations generated net losses from discontinued operations of $1 million
      and
      $40 million for the three months ended September 30, 2007 and 2006,
      respectively.




CCO’s
      operations generated net losses from discontinued operations of $280 million
      and
      $114 million for the nine months ended September 30, 2007 and 2006,
      respectively. Net losses from discontinued operations for the nine months ended
      September 30, 2007, primarily represent the $349 million after-tax charge
      associated with exit costs, partially offset by unrealized mark-to-market gains
      related to the increase in natural gas prices.




75


**CCO
      – DeSoto and Rowan Generation Facilities**




On
      May 2,
      2006, our board of directors approved a plan to divest of two subsidiaries
      of
      PVI, DeSoto County Generating Co., LLC (DeSoto) and Rowan County Power, LLC
      (Rowan). DeSoto owns a 320 MW dual-fuel combustion turbine electric generation
      facility in DeSoto County, Fla., and Rowan owns a 925 MW dual-fuel combined
      cycle and combustion turbine electric generation facility in Rowan County,
      N.C.
      On May 8, 2006, we entered into definitive agreements to sell DeSoto and Rowan,
      including certain existing power supply contracts, to Southern Power Company,
      a
      subsidiary of Southern Company, for gross sales prices of approximately $80
      million and $325 million, respectively. We used the proceeds from the sales
      to
      reduce debt and for other corporate purposes.




The
      sale
      of DeSoto closed in the second quarter of 2006 and the sale of Rowan closed
      during the third quarter of 2006. We recorded an after-tax loss during the
      nine
      months ended September 30, 2006, on the sale of DeSoto and Rowan of $65
      million.




DeSoto
      and Rowan operations generated combined net earnings from discontinued
      operations of $18 million and $9 million for the three and nine months ended
      September 30, 2006, respectively.




**NATURAL
      GAS DRILLING AND PRODUCTION**




On
      October 2, 2006, we sold our natural gas drilling and production business (Gas)
      to EXCO Resources, Inc. for approximately $1.1 billion in net proceeds. Gas
      included Winchester Production Company, Ltd. (Winchester Production),
      Westchester Gas Company, Texas Gas Gathering and Talco Midstream Assets Ltd.;
      all were subsidiaries of Progress Fuels. We used the proceeds from the sale
      primarily to reduce holding company debt and for other corporate
      purposes.




Based
      on
      the net proceeds associated with the sale, we recorded an after-tax net gain
      on
      disposal of $300 million during the year ended December 31, 2006. We recorded
      an
      after-tax loss of $1 million during the three months ended March 31, 2007,
      primarily related to working capital adjustments.




Gas
      operations generated net earnings from discontinued operations of $1 million
      for
      the three and nine months ended September 30, 2007. Net earnings from
      discontinued operations were $57 million and $84 million for the three and
      nine
      months ended September 30, 2006, respectively.




**PROGRESS
      TELECOM, LLC**




On
      March
      20, 2006, we completed the sale of PT LLC to Level 3. We received gross proceeds
      comprised of cash of $69 million and approximately 20 million shares of Level
      3
      common stock valued at an estimated $66 million on the date of the sale. Our
      net
      proceeds from the sale of approximately $70 million, after consideration of
      minority interest, were used to reduce debt. Prior to the sale, we had a 51
      percent interest in PT LLC. See Note 11 for a discussion of the subsequent
      sale
      of the Level 3 stock.




Based
      on
      the net proceeds associated with the sale and after consideration of minority
      interest, we recorded an after-tax net gain on disposal of $24 million during
      the three months ended March 31, 2006. During the three months ended June 30,
      2006, we recorded an additional after-tax gain of $5 million in connection
      with
      certain tax matters. During the three months ended September 30, 2006, we
      recorded a $1 million adjustment related to additional tax expenses resulting
      in
      a total after-tax gain of $28 million for the nine months ended September 30,
      2006.




Net
      earnings from discontinued operations for PT LLC were $2 million for the three
      months ended September 30, 2006. Net losses from discontinued operations were
      $3
      million for the nine months ended September 30, 2006.




76


**DIXIE
      FUELS AND OTHER FUELS BUSINESS**




On
      March
      1, 2006, we sold our 65 percent interest in Dixie Fuels Limited (Dixie Fuels)
      to
      Kirby Corporation for $16 million in cash. Dixie Fuels operates a fleet of
      four
      ocean-going dry-bulk barge and tugboat units. Dixie Fuels primarily transports
      coal from the lower Mississippi River to Progress Energy’s Crystal River
      facility. We recorded an after-tax gain of $2 million on the sale of Dixie
      Fuels.




Net
      earnings from discontinued operations were $3 million and $6 million for the
      three and nine months ended September 30, 2006, respectively.




**COAL
      MINING BUSINESSES**




On
      November 14, 2005, our board of directors approved a plan to divest of five
      subsidiaries of Progress Fuels engaged in the coal mining business (Coal
      Mining). On May 1, 2006, we sold certain net assets of three of our coal mining
      businesses to Alpha Natural Resources, LLC for gross proceeds of $23 million
      plus a $4 million working capital adjustment. As a result, during the nine
      months ended September 30, 2006, we recorded an after-tax loss of $13 million
      on
      the sale of these assets. The remaining coal mining operations are expected
      to
      be sold by March 31, 2008.




Net
      losses from discontinued operations for Coal Mining were $1 million and net
      earnings from discontinued operations were $3 million for the three months
      ended
      September 30, 2007 and 2006, respectively. Net losses from Coal Mining
      discontinued operations were $9 million and $1 million for the nine months
      ended
      September 30, 2007 and 2006, respectively.




**LIQUIDITY
      AND CAPITAL RESOURCES**




**Overview**




Progress
      Energy, Inc. is a holding company and, as such, has no revenue-generating
      operations of its own. Our primary cash needs at the Parent level are our common
      stock dividend and interest and principal payments on our $2.6 billion of senior
      unsecured debt. Our ability to meet these needs is dependent on the earnings
      and
      cash flows of the Utilities and our nonregulated subsidiaries, and the ability
      of our subsidiaries to pay dividends or repay funds to us. Our other significant
      cash requirements arise primarily from the capital-intensive nature of the
      Utilities’ operations, including expenditures for environmental compliance. We
      rely upon our operating cash flow, primarily generated by the Utilities,
      commercial paper and bank facilities, and our ability to access the long-term
      debt and equity capital markets for sources of liquidity.




The
      majority of our operating costs are related to the Utilities. Most of these
      costs are recovered from ratepayers in accordance with various rate plans.
      We
      are allowed to recover certain fuel, purchased power, environmental 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 do not materially
      affect net income.




As
      a
      registered holding company, we are subject to regulation by the 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.




Cash
      from
      operations, asset sales, short-term and long-term debt, and limited ongoing
      equity sales from our Investor Plus Stock Purchase Plan, employee benefit plan
      and existing stock options are expected to fund capital expenditures, common
      stock dividends, and debt service for the remainder of 2007. For fiscal year
      2007, we expect to realize an aggregate amount of approximately $150 million
      from the sale of stock through these plans.




77


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 2006 Form
      10-K.




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




**Historical
      for 2007 Compared to 2006**




**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 from continuing
      operations decreased by $552 million for the nine months ended September 30,
      2007, when compared to the corresponding period in the prior year. The decrease
      in operating cash flow was primarily due to a $169 million decrease in the
      recovery of fuel costs and changes in working capital related to a $157 million
      decrease from the change in accounts receivable, primarily at PEC, $65 million
      in premiums paid for derivative contracts (see Note 9A), and approximately
      $406
      million due to income tax impacts. The tax impacts were largely driven by the
      costs to exit the Georgia Contracts and income tax payments related to the
      sale
      of Gas, partially offset by lower income tax payments at the Utilities. The
      decrease from the change in accounts receivable at PEC was primarily due to
      higher collections in the prior year of wholesale billings and the impact of
      weather. These impacts were partially offset by a $98 million increase from
      the
      change in inventory, primarily related to prior year coal inventory purchases
      at
      PEF, and $45 million in net refunds in 2007 of cash collateral previously paid
      to counterparties on derivative contracts compared to $52 million in net cash
      payments in 2006 at PEF.




**INVESTING
      ACTIVITIES**




Net
      cash
      used by investing activities increased by $437 million for the nine months
      ended
      September 30, 2007, when compared to the corresponding period in the prior
      year.
      This is due primarily to a $392 million increase in capital expenditures for
      utility property additions, a $127 million increase in nuclear fuel additions,
      and a $57 million increase in net purchases of short-term investments included
      in available-for-sale securities and other investments. These impacts were
      partially offset by a $111 million increase in proceeds from sales of
      discontinued operations and other assets, net of cash divested. At PEC, the
      increase in utility property additions was primarily due to environmental
      compliance expenditures. At PEF, the increase in utility property additions
      was
      primarily due to repowering the Bartow plant to more efficient natural
      gas-burning technology and environmental compliance projects. The increase
      in
      nuclear fuel additions was largely driven by an additional refueling outage
      at
      PEC in 2007. 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, 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 3A), working capital adjustments for Gas, and the sale of poles at Progress
      Telecommunications Corporation (PTC).




During
      the nine months ended September 30, 2006, proceeds from sales of discontinued
      operations and other assets, net of cash divested primarily included
      approximately $80 million and $325 million, respectively, from the sale of
      DeSoto and Rowan (See Note 3C), approximately $70 million from the sale of
      PT
      LLC (See Note 3D), approximately $27 million from the sale of certain net assets
      of the coal mining business (See Note 3F), and approximately $16 million from
      the sale of Dixie Fuels (See Note 3E).




**FINANCING
      ACTIVITIES**




Net
      cash
      provided by financing activities was $682 million for the nine months ended
      September 30, 2007, compared to net cash used by financing activities of $1.123
      billion for the nine months ended September 30, 2006, for a net increase in
      cash
      provided by financing activities of $1.805 billion. The change in cash provided
      (used) by financing activities was due primarily to the 2007 financing
      activities described below and the March 1, 2006 maturity of $800 million 6.75%
      senior unsecured notes. These notes were paid with net proceeds from the sale
      of
      $400 million in senior notes and a combination of available cash and commercial
      paper proceeds. On January 13,




78


2006,
      Progress Energy issued $300 million of 5.625% Senior Notes due 2016 and $100
      million of Series A Floating Rate Senior Notes due 2010.




On
      July
      2, 2007, PEF paid at maturity $85 million of its 6.81% Medium-Term Notes with
      available cash on hand and commercial paper borrowings.




On
      August
      15, 2007, due to extreme volatility in the commercial paper market, Progress
      Energy borrowed $400 million under its $1.13 billion revolving credit agreement
      (RCA) to repay outstanding commercial paper. At September 30, 2007, $400 million
      of Progress Energy’s RCA loan was still outstanding. On October 17, 2007,
      Progress Energy used $200 million of commercial paper proceeds to repay a
      portion of the amount borrowed under the RCA. We will continue to monitor the
      commercial paper and short-term credit markets to determine when to repay the
      remaining balance of the RCA loan, while maintaining an appropriate level of
      liquidity.




On
      August
      15, 2007, due to extreme volatility in the commercial paper market, PEC borrowed
      $300 million under its $450 million RCA and paid at maturity $200 million of
      its
      6.80% First Mortgage Bonds. At September 30, 2007, $150 million of PEC’s RCA
      loan was still outstanding. On October 17, 2007, PEC repaid the remaining $150
      million of its RCA loan using available cash on hand.




On
      September 18, 2007, PEF issued $500 million of First Mortgage Bonds, 6.35%
      Series due 2037 and $250 million of First Mortgage Bonds, 5.80% Series due
      2017.
      The proceeds were used to repay PEF’s utility money pool borrowings and the
      remainder was placed in temporary investments for general corporate use as
      needed.




At
      December 31, 2006, we had 500 million shares of common stock authorized under
      our charter, of which approximately 256 million were outstanding. At December
      31, 2006, we had approximately 54 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, 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 Investor Plus
      Stock Purchase Plan. For the three months ended September 30, 2006, we issued
      approximately 0.3 million shares of common stock resulting in approximately
      $13
      million in proceeds, primarily to meet the requirements of the Investor Plus
      Stock Purchase Plan. For the nine months ended September 30, 2006, we issued
      approximately 1.7 million shares of common stock resulting in approximately
      $73
      million in proceeds. Included in these amounts were approximately 1.4 million
      shares for proceeds of approximately $58 million to meet the requirements of
      the
      401(k) Plan and the Investor Plus Stock Purchase Plan.




**DISCONTINUED
      OPERATIONS**




Net
      cash
      used by discontinued operations increased by $194 million for the nine months
      ended September 30, 2007, when compared to the corresponding period in the
      prior
      year. This increase was primarily due to a $335 million increase in cash used
      by
      operating activities, driven by a net cash payment of $347 million, representing
      the net cost to assign the Georgia Contracts and other related contracts (See
      Note 3A). This increase was partially offset by a $141 million decrease in
      cash
      used by investing activities, largely driven by the impact of 2006 property
      additions at Gas prior to its divestiture.




**Future
      Liquidity and Capital Resources**




At
      September 30, 2007, 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 2006 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 operations are expected to produce positive operating cash
      flow
      in the future when tax credits are realized for tax purposes (See “Other Matters
– Synthetic Fuels Tax Credits”).




79


We
      expect
      cash from operations plus availability under our credit facilities and shelf
      registration statements to be sufficient to meet our requirements in the near
      term. To the extent necessary, we may also use limited ongoing equity sales
      from
      our Investor Plus Stock Purchase Plan, employee benefit plan and existing stock
      options to meet our liquidity requirements.




As
      discussed in “Capital Expenditures,” under LIQUIDITY AND CAPITAL RESOURCES and
“Strategy” under INTRODUCTION in Item 7 to the 2006 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 will require the Utilities to make significant capital
      investments. We expect these anticipated capital investments to be funded
      through a combination of long-term debt, preferred stock and common equity,
      which is 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, construction and operational risks associated
      with
      new baseload generation.




The
      amount and timing of future sales of company 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 general corporate purposes.




At
      September 30, 2007, the current portion of our long-term debt was $464 million,
      which we expect to fund with cash from operations, commercial paper borrowings
      and/or long-term debt issuances.




**CREDIT
      RATING MATTERS**




On
      September 6, 2007, Standard & Poor’s Rating Services (S&P) upgraded the
      first mortgage bonds of both PEC and PEF to A- from BBB+ as a result of a
      methodology change for collateral coverage requirements. Because both PEC and
      PEF had asset to potential secured debt ratios of less than 1.5, they were
      assigned a recovery rating of 1, which qualified for a one notch increase over
      their corporate credit ratings.




On
      July
      13, 2007, Fitch Ratings (Fitch) upgraded the long-term ratings of both PEC
      and
      PEF to A- from BBB+ and revised their rating outlooks to stable from positive.
      Fitch cited cash flow coverage and leverage credit ratios more consistent with
      the ‘A’ rating category at the individual utilities, sound utility operations,
      and operations in historically favorable regulatory environments as the primary
      factors for the upgrades. Fitch also noted lowered group linkage risks for
      PEC
      and PEF resulting from improved business risk at the Parent due to the sale
      or
      wind-down of non-utility operations and reduced debt.




On
      June
      15, 2007, Moody’s Investors Service, Inc. (Moody’s) upgraded the corporate
      credit rating for PEC to A3 from Baa1 and revised its outlook to stable from
      positive. Moody’s cited strong cash flow coverage measures and financial
      metrics, operations in constructive regulatory environments with growing service
      territories, and lower debt and business risk at the Parent as the primary
      factors in the upgrade.




On
      March
      15, 2007, S&P upgraded corporate credit ratings to BBB+ from BBB at Progress
      Energy, Inc., PEC and PEF and revised each company’s outlook to stable from
      positive. S&P cited the significant reduction in our holding company debt
      and the moderation of business risk achieved by our renewed focus on our
      regulated utilities as the primary factors in the upgrade.




**REGULATORY
      MATTERS AND RECOVERY OF COSTS**




Regulatory
      matters, as discussed in “Other Matters – Regulatory Environment” and Note 4,
      and filings for recovery of environmental costs, as discussed in Note 12 and
      in
“Other Matters – Environmental Matters” of this filing and in Note 22 and in
“Other Matters – Environmental Matters” of the 2006 Form 10-K may impact our
      future liquidity and financing activities. The impacts of these matters,
      including the timing of recoveries from ratepayers, can be both a source of
      and
      a use of future liquidity resources. Developments since our 2006 Form 10-K
      are
      discussed below.




80


**PEC
      Base Rates**




On
      March
      23, 2007, PEC filed a petition with the North Carolina Utility Commission (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 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 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
      Associations (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. We cannot predict the outcome of this matter.




**PEC
      Fuel Cost Recovery**




On
      May 2,
      2007, PEC filed with the Public Service Commission of South Carolina (SCPSC)
      for
      an increase in the fuel rate charged to its South Carolina ratepayers. On June
      27, 2007, the SCPSC approved a settlement agreement filed jointly by PEC and
      all
      other parties to the proceedings. The settlement agreement resolved all issues
      and provided for a $12 million increase in fuel rates. Effective July 1, 2007,
      residential electric bills increased by $1.83 per 1,000 kWhs, or 1.9 percent,
      for fuel cost recovery.




On
      June
      8, 2007, PEC filed with the NCUC for an increase in the fuel rate charged to
      its
      North Carolina ratepayers. PEC asked the NCUC to approve a $48 million increase
      in fuel rates for under-recovered fuel costs associated with prior year
      settlements, as discussed below. On September 25, 2007, the NCUC approved PEC’s
      petition. The increase took effect October 1, 2007, and increased residential
      electric bills by $1.30 per 1,000 kWhs, or 1.3 percent, for fuel cost
      recovery.




On
      June
      2, 2006, PEC filed with the NCUC for an increase in the fuel rate charged to
      its
      North Carolina ratepayers. On September 25, 2006, the NCUC approved a settlement
      agreement filed jointly by PEC, the NCUC Public Staff and CIGFUR, which included
      a three-year phase-in of the increase in rates.




On
      November 21, 2006, CUCA filed an appeal with the North Carolina Tenth District
      Court of Appeals of the NCUC’s September 25, 2006, order on the grounds that the
      NCUC does not have the statutory authority to establish fuel rates for more
      than
      one year. PEC filed a motion to dismiss with the Court of Appeals on March
      22,
      2007. On October 24, 2007, CUCA filed a motion to withdraw their
      appeal.




**PEF
      Pass-through Clause Cost Recovery**




On
      September 4, 2007, PEF filed a request with the FPSC seeking approval of a
      cost
      adjustment to reflect a projected over-collection of fuel costs in 2007,
      declining projected charges for fuel for 2008, and other recovery clause
      factors. PEF asked the FPSC to approve a $163 million, or 4.53 percent, decrease
      in rates effective January 1, 2008. This cost adjustment would decrease
      residential bills by $5.00 for the first 1,000 kWhs. As discussed in “Other
      Regulatory Matters” below, residential base rates will increase effective
      January 1, 2008, by $2.73 for the first 1,000 kWhs. After considering the net
      effect of the base rate increase and the proposed fuel cost adjustment, 2008
      residential bills would decrease by a net amount of $2.27 for the first 1,000
      kWhs. The FPSC is scheduled to hold hearings on the cost adjustment proposal
      on
      November 6, 2007. We cannot predict the outcome of this matter.




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 sulfur dioxide
      (SO2) allowance
      costs associated with PEF’s purported failure to utilize the most economical
      sources of coal at Crystal River Unit 4 and Crystal River Unit 5 (CR4 and CR5)
      during the period 1996 to 2005. The OPC subsequently revised its claim to $135
      million, plus interest. 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, inclusive of interest, over a 12-month period beginning January 1,
      2008. On October 25, 2007, the OPC requested the FPSC to




81


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. PEF is also evaluating its options, including a request an appeal to
      the
      Florida Supreme Court of the FPSC’s October 10, 2007 order. We cannot predict
      the outcome of this matter. The FPSC also ordered PEF to address whether it
      was
      prudent in its 2006 and 2007 coal purchases for CR4 and CR5. On October 4,
      2007,
      PEF filed a motion to establish a separate docket on the prudence of its coal
      purchases for CR4 and CR5 for the years 2006 and 2007. On October 17, 2007,
      the
      FPSC granted that motion. The OPC filed testimony in support of its position
      to
      require PEF to refund at least $14 million for alleged excessive fuel recovery
      charges for 2006 coal purchases. PEF believes its coal procurement practices
      were prudent. We cannot predict the outcome of this matter.




On
      September 22, 2006, PEF filed a petition with the FPSC for Determination of
      Need
      to uprate Crystal River Unit No. 3 Nuclear Plant (CR3), bid rule exemption
      and
      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. On February 8, 2007, the FPSC issued
      an
      order approving PEF’s request for a need determination to uprate through a
      multi-stage uprate to be completed by 2012. PEF’s need determination filing
      included estimated project costs of approximately $382 million. On February
      2,
      2007, intervenors filed a motion to abate the cost-recovery portion of PEF’s
      request. On February 9, 2007, PEF requested that the FPSC deny the intervenors’
motion as legally deficient and without merit. On March 27, 2007, the FPSC
      denied the motion to abate and directed the staff of the FPSC to conduct a
      hearing on the matter to determine whether the revenue requirements of the
      uprate should be recovered through the fuel recovery clause. On May 4, 2007,
      PEF
      filed amended testimony clarifying the scope of the project. The FPSC held
      a
      hearing on this matter on August 7 and 8, 2007. The staff of the FPSC
      recommended that PEF be allowed to recover prudent and reasonable costs of
      Phase
      1, instrumentation modifications for improved accuracy, estimated at $6 million
      through the fuel clause. The staff of the FPSC recommended that the costs of
      all
      other phases, estimated at $376 million, be considered in a base rate
      proceeding. On October 19, 2007, PEF filed a notice of withdrawal of its cost
      recovery petition with the FPSC. PEF intends to re-file a petition in the fourth
      quarter of this year seeking cost recovery under Florida’s comprehensive energy
      bill enacted in 2006, and the FPSC's new nuclear cost recovery rule. We cannot
      predict the outcome of this matter.




**Other
      Regulatory Matters**




PEF
      filed
      a cost-recovery petition with the FPSC on April 30, 2007, to recover the full
      revenue requirements of Hines Unit 4, which has a current estimated in-service
      cost of $327 million, by increasing base rates $52 million, as provided for
      in
      PEF’s 2005 base rate agreement. The base rate increase would be effective upon
      placing Hines Unit 4 in service. The current estimate of in-service cost exceeds
      the initial project estimate of $286 million due to what we believe to be
      extraordinary circumstances. On September 27, 2007, the staff of the FPSC
      recommended that PEF be allowed to recover the full in-service costs, including
      the $41 million cost in excess of the Determination of Need and increase base
      rates $52 million effective December 1, 2007, for Hines Unit 4 and the related
      transmission facilities. The staff also recommended that the base rate changes
      associated with both Hines Unit 4 and Hines Unit 2 be achieved by applying
      the
      new rates to energy sales after December 1, 2007, thus requiring PEF to pro-rate
      the changes on customer bills rendered in December for customers that had
      consumption of electricity in both November and December. On October 12, 2007,
      PEF entered into a stipulation and settlement agreement that was filed with
      the
      FPSC. The agreement was reached with intervenors in settlement of all issues
      related to recovery of the revenue requirements of Hines Unit 4 and Hines Unit
      2
      and provides that PEF shall 1) increase its base rates for revenue requirements
      of Hines Unit 2 and Hines Unit 4 as approved in the staff recommendation and
      2)
      simplify the implementation of the base rate increase by making it effective
      with the first billing cycle in January 2008. On October 23, 2007, the FPSC
      voted to approve the stipulation and settlement agreement.




As
      discussed further in “Other Matters – Regulatory Environment”, South Carolina
      and North Carolina state energy legislation that became law in 2007 may impact
      our liquidity over the long term. Among other provisions, these 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. We anticipate that PEC’s reagent and purchased power costs
      eligible for jurisdictional recovery under the North Carolina and South Carolina
      energy laws will total approximately $50 million 2008.




82


Additionally,
      on July 13, 2007, the governor of Florida issued executive orders to address
      reduction of greenhouse gas emissions. The FPSC has held meetings regarding
      the
      renewable portfolio standard but no actions have been taken or rules issued.
      The
      Energy and Climate Action Team appointed by the governor submitted
      its initial recommendations for implementation of the governor’s executive
      orders on November 1, 2007. The recommendations encourage the development and
      implementation of energy efficiency and conservation measures, implementation
      of
      a climate registry, and consideration of a cap-and-trade approach to reducing
      the state's greenhouse gas emissions. Additional development and discussion
      of
      the recommendations will occur through a stakeholder process in 2008. The
      Florida Department of Environmental Protection held its first workshop on the
      greenhouse gas emissions cap on August 22, 2007, but we do not anticipate drafts
      of the rule to be issued until 2008. We cannot currently predict the impacts
      to
      our liquidity of complying with these executive orders.




The
      Energy Policy Act of 2005 (EPACT), among other provisions, gave the FERC
      accountability for system reliability and the authority to impose civil
      penalties. On June 18, 2007, compliance with 83 FERC-approved reliability
      standards became mandatory for all registered users, owners and operators of
      the
      bulk-power system, including PEC and PEF.




Based
      on
      FERC’s directive to revise 56 of the adopted standards, we expect standards to
      migrate to more definitive and enforceable requirements over time. We are
      committed to meeting those standards. The financial impact of mandatory
      compliance cannot currently be determined. Failure to comply with the
      reliability standards could result in the imposition of fines and civil
      penalties. If we are unable to meet the reliability standards for the bulk
      power
      system in the future, it could have a material adverse effect on our cash
      flows.




Prior
      to
      the effective date of mandatory compliance with the reliability standards,
      PEC
      self-reported two noncompliances and PEF self-reported three noncompliances.
      Entities responsible for enforcement of mandatory reliability standards have
      proposed that entities that self-reported noncompliance prior to the effective
      date and pursue aggressive mitigation plans will not be assessed fines. PEC
      and
      PEF have submitted mitigation plans to address the self-reported noncompliance.
      The costs of executing the mitigation plans are not expected to have a
      significant effect on our results of operations or liquidity.




**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 performance
      obligations under power supply agreements, tolling agreements, transmission
      agreements, gas agreements, fuel procurement agreements and trading operations.
      Our guarantees also include standby letters of credit and surety bonds. At
      September 30, 2007, we have issued $879 million of guarantees for future
      financial or performance assurance, including $29 million at PEC, $1 million
      at
      PEF and approximately $380 million related to PVI. Also included in the total
      amount is $300 million of guarantees for certain payments of two wholly owned
      indirect subsidiaries issued by the Parent (See Note 14). Subsequent to
      September 30, 2007, approximately $120 million of guarantees related to PVI
      were
      terminated. We do not believe conditions are likely for significant performance
      under the guarantees of performance issued by or on behalf of
      affiliates.




The
      majority of contracts supported by the guarantees contain provisions that
      trigger guarantee obligations based on downgrade events to below investment
      grade (below Baa3 or BBB-) by Moody’s or S&P for the Parent’s senior
      unsecured debt rating, ratings triggers, monthly netting of exposure and/or
      payments and offset provisions in the event of a default. At September 30,
      2007,
      the Parent’s senior unsecured debt rating was Baa2 by Moody’s and BBB by S&P
      and no guarantee obligations had been triggered. If the guarantee obligations
      were triggered, the liquidity requirements to support ongoing operations within
      a 60-day period, associated with guarantees for




83




Progress
      Energy’s nonregulated portfolio and power supply agreements, would not have had
      a material impact on our financial condition or liquidity at September 30,
      2007.




At
      September 30, 2007, 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,
      and for timely payment of obligations in support of our nonwholly owned
      synthetic fuels operations as discussed in 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 enter into various long- and short-term
      contracts for fuel requirements at our generating plants. Through September
      30,
      2007, contracts procured though our subsidiaries have increased our aggregate
      purchase obligations for fuel and purchased power by $4.274 billion from $13.133
      billion, as stated in Note 22A in the 2006 Form 10-K. Future obligations under
      operating leases also increased by approximately $413 million from $428 million
      at December 31, 2006. In September 2007, PEF issued long-term debt totaling
      $750
      million. These increases are discussed under “PEC” and “PEF” below.




**PEC**




Through
      September 30, 2007, PEC’s fuel and purchase power commitments increased by
      $1.015 billion from $4.358 billion, as stated in Note 22A in the 2006 Form
      10-K.
      This increase is primarily related to nuclear fuel commitments, of which
      approximately $412 million will be incurred through 2011, with the remainder
      incurred through 2018.




**PEF**




Through
      September 30, 2007, PEF’s fuel and purchase power commitments increased by
      $3.494 billion from $8.513 billion, as stated in Note 22A in the 2006 Form
      10-K.
      The increase is primarily due to precedent and related agreements PEF entered
      into on December 2, 2004, for the supply of natural gas and associated firm
      pipeline transportation to augment PEF’s gas supply needs for the period from
      May 1, 2007, to April 30, 2027, as discussed in Note 22A in the 2006 Form 10-K.
      At September 30, 2007, the total cost associated with these agreements is
      approximately $4.4 billion, an increase of $500 million from December 31, 2006,
      as payments under the gas supply agreement are based on a market index, which
      has increased since year-end. Based upon current market prices, we anticipate
      incurring these costs ratably over the contract period. The transactions were
      subject to several conditions precedent, some of which were satisfied at
      December 31, 2006. Due to the conditions in the agreements, the estimated costs
      associated with these agreements were not included in our or PEF’s contractual
      cash obligations table at December 31, 2006. During 2007, the remaining
      conditions precedent were satisfied and the long-term contracts were contractual
      obligations of PEF at September 30, 2007.




In
      August
      2007, PEF entered into a purchased power agreement, which is classified as
      an
      operating lease. The agreement calls for minimum annual payments of
      approximately $28 million from 2012 though 2027 for a total of approximately
      $420 million.




On
      September 18, 2007, PEF issued $500 million of First Mortgage Bonds, 6.35%
      Series due 2037 and $250 million of First Mortgage Bonds, 5.80% Series due
      2017
      (See Note 6).




84


**OTHER
      MATTERS**




**Synthetic
      Fuels Tax Credits**




Historically,
      we have had substantial operations associated with the production of coal-based
      solid synthetic fuels as defined under Section 29 of the Code (Section 29).
      The
      production and sale of these products qualifies for federal income tax credits
      so long as certain requirements are 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 entitle 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
      may
      be phased out if annual average market prices for crude oil exceed certain
      prices, as discussed below. Synthetic fuels are generally not economical to
      produce and sell absent the credits. The current synthetic fuels tax credit
      program expires at the end of 2007.




On
      September 14, 2007, we idled production of synthetic fuels at our majority-owned
      synthetic fuels facilities. As discussed below in “Impact Of Crude Oil Prices”,
      the decision to idle production was based on the current high level of oil
      prices and the resumption of synthetic fuels production was dependent upon
      a
      number of factors, including a reduction in oil prices. On October 12, 2007,
      based upon the continued high level of oil prices, unfavorable oil price
      projections through the end of 2007, and the expiration of the current synthetic
      fuels tax credit program at the end of 2007, we decided to permanently cease
      production of synthetic fuels at our majority-owned facilities. The operation
      of
      synthetic fuels facilities on behalf of third parties is expected to continue
      through December 31, 2007. Because we have abandoned our majority-owned
      facilities and our other synthetic fuels operations will cease as of December
      31, 2007, we expect to report all of our synthetic fuels operations as
      discontinued operations in the fourth quarter of 2007.




**TAX
      CREDITS**




Legislation
      enacted in 2005 redesignated the Section 29 tax credit as a general business
      credit under Section 45K of the Code (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 removes the regular federal income tax liability limit
      on synthetic fuels production and subjects the credits to a 20-year carry
      forward period. This provision would allow us to produce more coal-based solid
      synthetic fuels than we have historically produced, should we choose to do
      so.




Total
      Section 29/45K credits generated through September 30, 2007 (including those
      generated by Florida Progress Corporation (Florida Progress) prior to our
      acquisition), were approximately $2.024 billion, of which $1.069 billion has
      been used to offset regular federal income tax liability, $845 million is being
      carried forward as deferred tax credits and was recorded as a reduction of
      noncurrent income tax liabilities on the Consolidated Balance Sheet, and $110
      million has been reserved due to the estimated phase-out of tax credits due
      to
      high oil prices in 2007, as described below.




**IMPACT
      OF CRUDE OIL PRICES**




Although
      the Section 29/45K tax credit program is expected to continue through 2007,
      recent market conditions, world events and catastrophic weather events have
      increased the volatility and level of oil prices, which reduced the value of
      the
      credits for 2006 and could limit or entirely eliminate the amount of credits
      for
      2007. This possibility is due to a provision of Section 29 that provides that
      if
      the average wellhead price per barrel for unregulated domestic crude oil for
      the
      year (the Annual Average Price) exceeds a certain threshold price (the Threshold
      Price), the value of Section 29/45K tax credits is reduced for that year. Also,
      if the Annual Average Price increases high enough (the Phase-out Price), the
      value of Section 29/45K tax credits are eliminated for that year. The Threshold
      Price and the Phase-out Price are adjusted annually for inflation.




If
      the
      Annual Average Price falls between the Threshold Price and the Phase-out Price
      for a year, the amount by which Section 29/45K tax credits are reduced will
      depend on where the Annual Average Price falls in that




85


continuum.
      The Department of the Treasury calculates the Annual Average Price based on
      the
      Domestic Crude Oil First Purchases Prices published by the Energy Information
      Agency (EIA). Because the EIA publishes its information on a three-month lag,
      the secretary of the Treasury finalizes the calculations three months after
      the
      year in question ends. Thus, the Annual Average Price for calendar year 2006
      was
      published on April 4, 2007. Based on the Annual Average Price of $59.68, our
      synthetic fuels tax credits generated during 2006 were reduced by 33 percent,
      or
      approximately $35 million.




We
      estimate that the 2007 Threshold Price will be approximately $57 per barrel
      and
      the Phase-out Price will be approximately $71 per barrel, based on an estimated
      inflation adjustment for 2007. The monthly Domestic Crude Oil First Purchases
      Price published by the EIA has recently averaged approximately $5 lower than
      the
      corresponding daily New York Mercantile Exchange (NYMEX) prompt month settlement
      price for light sweet crude oil. Through September 30, 2007, the average NYMEX
      settlement price for light sweet crude oil was $66.18 per barrel, and as of
      September 30, 2007, the average NYMEX futures price for light sweet crude oil
      for the remainder of calendar year 2007 was $80.27 per barrel. This results
      in a
      weighted-average annual price for light sweet crude oil of approximately $69.80
      per barrel for calendar year 2007. Based upon the estimated 2007 Threshold
      Price
      and Phase-out Price, if oil prices for 2007 averaged this weighted price of
      approximately $69.80 per barrel for the entire year in 2007, we estimate that
      the synthetic fuels tax credit amount for 2007 would be reduced by approximately
      55 percent. Therefore, we reserved 55 percent or approximately $110 million
      of
      the $200 million of tax credits generated during the first nine months of 2007.
      As of September 30, 2007, the NYMEX price of oil for the remainder of 2007
      would
      have to be $49.89 to have no reduction in value of tax credits generated during
      2007 and would have to be $104.04 to have a full reduction in value. The final
      calculations of any reductions in the value of the tax credits will not be
      determined until April 2008 when final 2007 oil prices are published. Additional
      fluctuations in oil prices through the end of 2007, which impact the estimated
      weighted-average annual price of oil for 2007, may cause quarterly adjustments,
      either positive or negative, to our results of operations and the amount of
      tax
      credits we reserve.




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
      NYMEX basis. The notional quantity of these oil price hedge instruments is
      25
      million barrels and will provide protection for the equivalent of approximately
      eight million tons of 2007 synthetic fuels production and will be
      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 3I, we disposed of our 100 percent ownership interest in Ceredo
      in
      March 2007. Through September 30, 2007, we have fully utilized the production
      levels necessary to maximize the potential benefits of the economic hedge.
      See
      Note 9 and Item 3, “Quantitative and Qualitative Disclosures About Market Risk,”
for a discussion of market risk and derivatives.




As
      discussed above, on October 12, 2007, we permanently abandoned operations at
      our
      majority-owned synthetic fuels facilities. If the 2007 tax credits earned to
      date were completely phased out due to high oil prices, we would reverse an
      additional $90 million of income related to tax credits recorded during the
      first nine months of 2007. We would expect that additional favorable
      mark-to-market adjustments on the derivative contracts would partially mitigate
      such a reversal.




**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 produces and sells 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 are received as we produce
      and
      sell qualifying coal-based solid synthetic fuels on behalf of the buyer during
      2007. As of September 30, 2007, we have received payments of $27 million on
      the
      note. Actual proceeds could differ based on actual production levels, which
      shall be determined by the buyer. The estimated production level of Ceredo
      subsequent to the transaction is 2.8 million tons. As of September 30, 2007,
      we
      have produced 2.0 million tons. Pursuant to the terms of the disposal agreement,
      the buyer has the right to unwind the transaction if an Internal Revenue Service
      (IRS) reconfirmation private letter ruling is not received by November 9, 2007,
      or if certain adverse changes in tax law, as defined in the agreement, occur
      before November 19, 2007. Therefore, no gain on the disposal will be recognized
      prior to the expiration of these rights. Once these rights expire, deferred
      gains, if any,




86


from
      the
      disposal will be recognized over time as we produce and sell qualifying
      coal-based solid synthetic fuels for the buyer and when there is persuasive
      evidence that the sales proceeds have become fixed or determinable and
      collectability is reasonably assured. The IRS reconfirmation private letter
      ruling was received on October 29, 2007.****Subsequent to the
      disposal, we remain the primary beneficiary of Ceredo and continue to
      consolidate Ceredo in accordance with FIN 46R, but we have recorded a 100
      percent minority interest. Consequently, subsequent to the disposal there is no
      net earnings impact from Ceredo’s operations and our net investment in Ceredo is
      zero. In connection with the disposal, Progress Fuels and Progress Energy
      provided guarantees and indemnifications for certain legal and tax matters
      to
      the buyer, which reduces any potential deferred gain. The ultimate resolution
      of
      these matters could result in adjustments to the gain, if any, on disposal
      in
      future periods. See Note 3I for additional discussion of this transaction and
      Note 13B for a general discussion of guarantees.




In
      June
      2004, through our subsidiary Progress Fuels, we sold in two transactions a
      combined 49.8 percent partnership interest in Colona, one of our coal-based
      solid synthetic fuels facilities. Substantially all proceeds from the sales
      will
      be received over time, which is typical of such sales in the industry. Gains
      from the sales will be recognized on a cost-recovery basis as the facility
      produces and sells synthetic fuels and when there is persuasive evidence that
      the sales proceeds have become fixed or determinable, collectability is
      reasonably assured and payments are non-refundable. Gain recognition is
      dependent on the synthetic fuels production qualifying for Section 29/45K tax
      credits and the value of such tax credits as discussed above. Until there is
      persuasive evidence that the gain recognition criteria are met, proceeds from
      selling interests in Colona will be deferred to subsequent quarters, or to
      a
      subsequent calendar year. This could result in shifting earnings from earlier
      quarters to later quarters in a calendar year or to a subsequent calendar year.
      In the event that the synthetic fuels tax credits from the Colona facility
      are
      reduced, including from an extended idling of our production due to an increase
      in the price of oil that could limit or eliminate synthetic fuels tax credits,
      the amount of proceeds realized from the sale could be significantly impacted.
      At September 30, 2007, proceeds from monetization of $14 million have been
      deferred. Based on the current level of oil prices, it is unlikely that these
      proceeds will be recognized.




See
      Note
      13B for additional discussion related to our synthetic fuels
      operations.




**Regulatory
      Environment**




The
      Utilities’ operations in North Carolina, South Carolina and Florida are
      regulated by the NCUC, SCPSC and the FPSC, respectively. The Utilities are
      also
      subject to regulation by the FERC, the Nuclear Regulatory Commission (NRC)
      and
      other federal and state agencies common to the utility business. As a result
      of
      regulation, many of the fundamental business decisions, as well as the rate
      of
      return the Utilities are permitted to earn, are subject to the approval of
      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.




In
      2007,
      the U.S. House of Representatives passed energy bill H.R. 3221 and the U.S.
      Senate passed energy bill H.R. 6. Provisions in these bills include: a proposal
      for a 15% Federal Renewable Portfolio Standard (only included in the House
      bill), provisions for a Corporate Average Fuel Economy standard for automobiles,
      provisions for funding of research on clean coal technologies, incentives for
      plug-in hybrid vehicles and incentives for increased energy efficiency.
      Discussions are continuing between the two chambers in an effort to convene
      a
      conference committee to work through differences in the bills in an attempt
      to
      produce a conference report. We are continuing to monitor these discussions
      and
      are unable to predict if these congressional efforts will result in an energy
      bill that would ultimately be sent to the President to be signed into law.
      The
      specific requirements of the proposed legislation and associated costs, if
      any,
      cannot be predicted.





During
      2007, the North Carolina legislature passed comprehensive energy legislation,
      which became law on August 20, 2007. The law establishes a minimum Renewable
      Energy and Energy Efficiency Portfolio Standard (REPS) for




87


the
      use
      of energy from specified renewable energy resources or implementation of energy
      efficiency measures by the state’s electric utilities beginning with a 3 percent
      requirement in 2012 and increasing to 12.5 percent in 2021 for regulated public
      utilities, including PEC. The premium to be paid by electric utilities to comply
      with the requirements above the cost they would have otherwise incurred to
      meet
      consumer demand, is to be recovered through an annual rider. The annual amount
      that can be recovered through the REPS rider is capped and once a utility has
      expended monies equal to the cap, the utility is deemed to have met its
      obligations under the REPS, regardless of the actual renewables generated or
      purchased. The law grants the NCUC authority to modify or alter the REPS
      requirements if the NCUC determines it is in the public interest to do
      so.




The
      law
      allows the utility to meet a portion of the REPS with energy reductions achieved
      through energy efficiency programs. Energy efficiency programs include any
      program or activity implemented after January 1, 2007, that results in less
      energy being used to perform the same function. Through the year 2020, a utility
      can use energy efficiency programs to satisfy up to 25 percent of their REPS;
      beginning in 2021, these programs may constitute up to 40 percent of the
      requirements.




The
      law
      allows the utility to recover the costs of new demand-side management
      (DSM)/energy efficiency programs through an annual DSM rider. The law allows
      the
      utility 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 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 and interruptible load. PEC has begun implementing a series
      of energy efficiency/DSM programs and deferred an immaterial amount of
      implementation and program costs for future recovery through the nine months
      ended September 30, 2007.




The
      law
      also expands the definition of the traditional fuel clause so that additional
      costs may be recovered annually. These additional costs include costs of
      reagents (commodities such as ammonia and limestone used in emissions control
      technologies), renewable energy and certain components of purchased power not
      previously recoverable through the fuel clause (see additional discussion
      below). The North Carolina law also authorizes the NCUC to allow annual prudence
      reviews of the construction costs of a baseload generating plant if requested
      by
      the public utility that is constructing the plant 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.




On
      October 26, 2007, the NCUC issued its proposed rules for implementation of
      the
      law and reconfirmed its intention to complete the rulemaking process by January
      1, 2008. Until the rulemaking process is completed, we cannot predict the costs
      of complying with the law. PEC would be able to annually recover its reasonable
      prudent compliance costs.




During
      2007, the South Carolina legislature ratified new energy legislation, which
      became law on May 3, 2007. Key elements of the law include expansion of the
      annual fuel clause mechanism to include recovery of the costs of reagents used
      in the operation of PEC’s emissions control technologies (see additional
      discussion below). The law also includes provisions to provide base rate cost
      recovery for upfront development costs associated with nuclear baseload
      generation and construction costs associated with nuclear or coal baseload
      generation without a base rate proceeding and the ability to recover financing
      costs for new nuclear baseload generation through annual riders.




We
      anticipate PEC’s reagent and purchased power costs eligible for jurisdictional
      recovery under the North Carolina and South Carolina energy laws will total
      approximately $50 million in 2008.




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)




88


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 but no actions have been taken or rules issued.
      The Energy and Climate Action Team appointed by the governor submitted
      its initial recommendations for implementation of the governor’s executive
      orders on November 1, 2007. The recommendations encourage the development and
      implementation of energy efficiency and conservation measures, implementation
      of
      a climate registry, and consideration of a cap-and-trade approach to reducing
      the state's greenhouse gas emissions. Additional development and discussion
      of
      the recommendations will occur through a stakeholder process in 2008. The
      Florida Department of Environmental Protection held its first workshop on the
      greenhouse gas emissions cap on August 22, 2007, but we do not anticipate drafts
      of the rule to be issued until 2008. We cannot currently predict the costs
      of
      complying with the laws and regulations that may ultimately result from these
      executive orders. Our balanced solution, as described in “Increasing Energy
      Demand”, includes greater investment in energy efficiency, renewable energy and
      state-of-the-art generation and demonstrates our commitment to environmental
      responsibility.




On
      April
      10, 2007, the FPSC adopted a rule that specifies what storm costs will be
      recoverable and whether such recoverable costs would be offset against a
      utility’s storm reserve fund or recoverable through its base rates. PEF does not
      believe that compliance with this rule will materially increase its
      costs.




The
      Energy Policy Act of 2005 (EPACT), among other provisions, gave the FERC
      accountability for system reliability and the authority to impose civil
      penalties. EPACT provides procedures and rules for the establishment of an
      electric reliability organization (ERO) that will propose and enforce mandatory
      reliability standards. On July 20, 2006, the FERC certified the North American
      Electric Reliability Corporation (NERC) as the ERO. Included in this
      certification was a provision for the ERO to delegate authority for the purpose
      of proposing and enforcing reliability standards in particular regions of the
      country by entering into delegation agreements with regional entities. The
      SERC
      Reliability Corporation (SERC) and the Florida Reliability Coordinating Council
      (FRCC) are the regional entities for PEC and PEF, respectively.




In
      Order
      693, the FERC completed part of its EPACT implementation plan by approving
      83
      reliability standards developed by the NERC and set aside 24 standards pending
      further development. On June 18, 2007, compliance with the 83 FERC-approved
      reliability standards became mandatory for all registered users, owners and
      operators of the bulk-power system, including PEC and PEF. Prior to the FERC
      action, electric utility industry compliance with the NERC standards had been
      voluntary.




Based
      on
      FERC’s directive to revise 56 of the adopted standards, we expect standards to
      migrate to more definitive and enforceable requirements over time. We are
      committed to meeting those standards. The financial impact of mandatory
      compliance cannot currently be determined. Failure to comply with the
      reliability standards could result in the imposition of fines and civil
      penalties. If we are unable to meet the reliability standards for the bulk
      power
      system in the future, it could have a material adverse effect on our financial
      condition, results of operations and cash flows.




Prior
      to
      the effective date of mandatory compliance with the reliability standards,
      PEC
      self-reported noncompliance in two areas to SERC and PEF self-reported
      noncompliance in three areas to FRCC. The FRCC, SERC and NERC have proposed
      that
      entities that self-reported noncompliance prior to the effective date and pursue
      aggressive mitigation plans will not be assessed fines. PEC and PEF have
      submitted mitigation plans to SERC and FRCC, respectively, to address the
      self-reported noncompliance. The costs of executing the mitigation plans are
      not
      expected to have a significant impact on our results of operations or
      liquidity.




**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.




89


**Increasing
      Energy Demand**




Meeting
      the anticipated growth and resulting demand for electricity within the
      Utilities’ service territories will require a balanced approach, which includes
      a strong commitment to energy efficiency, investments in emerging alternative
      and renewable energy technologies and investments in state-of-the-art power
      plants.




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 ways for residential customers
      to
      reduce energy use, promotes home energy checks, provides tools and programs
      for
      large and small businesses to minimize their energy use and provides an
      interactive internet Web site with online calculators, programs and efficiency
      tips.




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




In
      the
      coming years, we will continue to invest in existing plants and consider plans
      for building new baseload plants. Due to the anticipated growth in our service
      territories, we estimate that we will require new baseload generation facilities
      in both Florida and the Carolinas by the middle of the next decade, and we
      are
      evaluating the best available options for this generation, including advanced
      design nuclear and clean coal technologies. At this time, no definitive
      decisions have been made to construct new baseload plants. While we pursue
      expansion of energy efficiency and conservation programs, PEC has announced
      a
      two-year moratorium on constructing new coal-fired plants and that if PEC goes
      ahead with a new nuclear plant, the new plant would not be online until at
      least
      2018 (see “Nuclear” below).




As
      authorized under EPACT, on October 4, 2007, the 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. Congress has approved $4 billion in loan guarantees, with the DOE
      seeking an additional $9 billion in loan guarantees in its fiscal 2008 budget
      request. Initial applications for loan guarantees were for non-nuclear projects
      but it is expected that approval of additional funding could result in
      guarantees being available for nuclear generation projects. We cannot predict
      the outcome of this matter.




**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 December 2008.




On
      January 16, 2007, the U.S. Supreme Court declined to hear an appeal of a Ninth
      Circuit U.S. Court of Appeals’ decision in which the Ninth Circuit held that the
      NRC is required to consider the environmental impacts of terrorist attacks
      under
      the National Environmental Policy Act in authorizing an independent spent fuel
      storage installation. Similar cases, including cases involving operating license
      renewals, are pending in seven other jurisdictions. The NRC is considering
      the
      scope and import of the Ninth Circuit’s decision in reviewing its operating
      license renewal program. In response to the Ninth Circuit’s decision, on
      February 26, 2007, the NRC reconfirmed that the National Environmental Policy
      Act does not require the NRC to consider the environmental consequences of
      hypothetical terrorist attacks on NRC-licensed facilities.




Our
      nuclear units are periodically removed from service to accommodate normal
      refueling and maintenance outages, repairs and certain other modifications
      (See
      Note 13C).




We
      have
      announced that we are pursuing development of combined license (COL)
      applications to potentially construct new nuclear plants. Our announcement
      is
      not a commitment to build a nuclear plant but is a necessary step




90


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 have selected the Westinghouse
      Electric AP1000 reactor design as the technology upon which to base PEC’s
      application submission. PEC expects to file the application for the COL in
      2008.
      If we receive approval from the NRC and applicable state agencies, and if the
      decisions to build are made, a new plant would not be online until at least
      2018
      (See “Increasing Energy Demand” above).




On
      December 12, 2006, we announced that PEF selected a site in Levy County, Fla.,
      to evaluate for possible future nuclear expansion. We have selected the
      Westinghouse Electric AP1000 reactor design as the technology upon which to
      base
      PEF’s application submission. PEF expects to file the application for the COL in
      2008. If we receive approval from the NRC and applicable state agencies, and
      if
      the decision to build is 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 September 2007, PEF completed the purchase of the
      3,100 acre Levy County site. PEF anticipates filing a need case with the FPSC
      in
      early 2008.




In
      2007,
      both the Levy County Planning Commission and the Board of Commissioners voted
      unanimously in favor of PEF’s requests to change the comprehensive land use
      plan. The Florida Department of Community Affairs (FDCA) reviewed the proposed
      changes to the comprehensive land use plan in September 2007. In their report,
      the FDCA expressed concerns related to the intensity of use and environmental
      suitability for some of the proposed amendments impacting PEF’s proposed Levy
      County nuclear site. We anticipate that the Levy County Planning Commission
      will
      resolve the FDCA’s concerns without impact to the potential project schedule. We
      cannot predict the outcome of this matter.




A
      new
      nuclear plant may be eligible for the federal production tax credits and risk
      insurance provided by the EPACT. EPACT provides an annual tax credit of 1.8
      cents per kWh for nuclear facilities for the first eight years of operation.
      The
      credit is limited to the first 6,000 MW of new nuclear generation in the United
      States and has an annual cap of $125 million per 1,000 MW of national MW
      capacity limitation allocated to the unit. In April 2006, the IRS provided
      interim guidance that the 6,000 MW of production tax credits generally will
      be
      allocated to new nuclear facilities that 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 comprehensive energy bill enacted in
      2006, the FPSC ordered new rules in December 2006 that would allow
      investor-owned utilities such as PEF to request partial recovery of the 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. 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. The North Carolina legislature ratified 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”).




91


**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.




**HAZARDOUS
      AND SOLID WASTE MANAGEMENT**




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 parties (PRP) groups. Various organic materials associated with
      the
      production of manufactured gas, generally referred to as coal tar, are regulated
      under federal and state laws. PEC and PEF are each PRPs at several manufactured
      gas plant (MGP) sites. We are also currently in the process of assessing
      potential costs and exposures at other sites. These costs are eligible for
      regulatory recovery through either base rates or cost-recovery clauses (See
      Notes 4 and 12). Both PEC and PEF evaluate potential claims against other PRPs
      and insurance carriers and plan to submit claims for cost recovery where
      appropriate. The outcome of these potential claims cannot be predicted. No
      material claims are currently pending. Hazardous and solid waste management
      matters are discussed in detail in Note 12A.




We
      accrue
      costs to the extent our liability is probable and the costs can be reasonably
      estimated in accordance with GAAP. Because the extent of environmental impact,
      allocation among PRPs for all sites, remediation alternatives (which could
      involve either minimal or significant efforts), and concurrence of the
      regulatory authorities have not yet reached the stage where a reasonable
      estimate of the remediation costs can be made, we cannot determine the total
      costs that may be incurred in connection with the remediation of all sites
      at
      this time. It is probable that current estimates could change and additional
      losses, which could be material, may be incurred in the future.




**AIR
      QUALITY AND WATER QUALITY**




We
      are,
      or may ultimately be, subject to various current and proposed federal, state
      and
      local environmental compliance laws and regulations, which would likely 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), SO2, carbon
      dioxide
      (CO2) and
      mercury. Some of these proposals establish nationwide caps and emission rates
      over an extended period of time. This national multi-pollutant 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
      will
      be installed pursuant to the provisions of the Clean Smokestacks Act, Clean
      Air
      Interstate Rule (CAIR,) Clean Air Mercury Rule (CAMR) and Clean Air Visibility
      Rule (CAVR), which are discussed below, may address some of the issues outlined
      above. CAVR requires the installation of best available retrofit technology
      (BART) on certain units. However, the outcome of these matters cannot be
      predicted.




The
      following tables contain information about our current estimates of capital
      expenditures to comply with environmental laws and regulations described below.
      These costs are eligible for regulatory recovery through either base rates
      or
      cost-recovery clauses. The outcome of future petitions for recovery cannot
      be
      predicted. Expenditures for the NOx SIP Call Rule under Section 110 of the
      Clean
      Air Act (NOx SIP Call) include the cost to install NOx controls under North
      Carolina’s and South Carolina’s programs to comply with the federal eight-hour
      ozone standard. The air quality controls installed to comply with the NOx SIP
      Call and Clean Smokestacks Act will result in a reduction of the costs to meet
      the CAIR requirements for our North Carolina units at PEC. We review our
      estimates on an ongoing basis. The timing and extent of the costs for future
      projects will depend upon final compliance strategies.




92







***Progress
                Energy*****Air
                and Water Quality Estimated Required Environmental
                Expenditures**
              *(in
                millions)*
            Estimated
                Timetable
            Total
                Estimated Expenditures
            Cumulative
                Spent through September 30, 2007NOx
                SIP Call
            2002–2007
            $342
            $342Clean
                Smokestacks Act
            2002–2013
            1,100
                – 1,400
            826CAIR/CAMR/CAVR
            2005–2018
            1,500
                – 2,600
            192Total
                air quality
            
            2,942
                – 4,342
            1,360Clean
                Water Act Section 316(b)(a)
            
            –
            –North
                Carolina Groundwater Standard(b)
            
            –
            –Total
                water quality
            
            –
            –Total
                air and water quality
            
            $2,942
                – $4,342
            $1,360





***PEC*****Air
                and Water Quality Estimated Required Environmental
                Expenditures**
              *(in
                millions)*
            Estimated
                Timetable
            Total
                Estimated Expenditures
            Cumulative
                Spent through September 30, 2007NOx
                SIP Call
            2002–2007
            $342
            $342Clean
                Smokestacks Act
            2002–2013
            1,100
                – 1,400
            826CAIR/CAMR/CAVR
            2005–2018
            200
                – 300
            6Total
                air quality
            
            1,642
                – 2,042
            1,174Clean
                Water Act Section 316(b)(a)
            
            –
            –North
                Carolina Groundwater Standard (b)
            
            –
            –Total
                water quality
            
            –
            –Total
                air and water quality
            
            $1,642
                – $2,042
            $1,174





***PEF*****Air
                and Water Quality Estimated Required Environmental
                Expenditures**
              *(in
                millions)*
            Estimated
                Timetable
            Total
                Estimated Expenditures
            Cumulative
                Spent through September 30, 2007CAIR/CAMR/CAVR
            2005–2018
            $1,300
                – $2,300
            $186Clean
                Water Act Section 316(b)(a)
            
            –
            –Total
                air and water quality
            
            $1,300
                – $2,300
            $186





(a)
            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.”


(b)
            Compliance
                plans will be determined upon finalization of the changes expected
                to be
                proposed to the North Carolina groundwater quality standard for
                arsenic.





**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 in excess of $1.0 billion. These settlement agreements have generally
      called for expenditures to be made over extended time periods, and some of
      the
      companies may seek recovery of the related costs through rate adjustments or
      similar mechanisms. On April 2, 2007, the U.S. Supreme Court issued a ruling
      on
      an appeal of a decision of the U.S. Court of Appeals for the Fourth Circuit,
      in
      a case involving an unaffiliated utility. The Fourth Circuit held that NSR
      applies to projects that result in an increase in maximum hourly emissions.
      The
      U.S. Supreme Court rejected the lower court decision and held that the EPA
      is
      not required to adopt the maximum hourly emissions test but may use an actual
      annual emissions test to determine whether NSR applies.




93


On
      March
      17, 2006, the U.S. Court of Appeals for the District of Columbia Circuit (D.C.
      Court of Appeals) set aside the EPA’s 2003 NSR equipment replacement rule. The
      rule would have provided a more uniform definition of routine equipment
      replacement, which is excluded from NSR applicability. The D.C. Court of Appeals
      denied a request by the EPA for a re-hearing regarding this matter on June
      30,
      2006. On November 27, 2006, the EPA filed a petition for a writ of certiorari
      requesting that the U.S. Supreme Court review the D.C. Court of Appeals’
decision. On April 30, 2007, the U.S. Supreme Court denied the EPA’s petition.
      In a previous case decided in late 2005, the D.C. Court of Appeals had also
      set
      aside a provision in the NSR rule that had exempted the installation of
      pollution control projects from review. These projects are now subject to NSR
      requirements, adding time and cost to the installation process.




**NOx
      SIP Call Rule under Section 110 of the Clean Air Act**




The
      NOx
      SIP Call is an EPA rule that requires 22 states, including North Carolina and
      South Carolina, to further reduce NOx emissions. The NOx SIP Call is not
      applicable to Florida. PEC has completed installation of controls to meet the
      NOx SIP Call requirements. Increased O&M expenses relating to the NOx SIP
      Call are not expected to be material to our or PEC’s results of
      operations.




**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 5,100 MW of coal-fired generation capacity in North Carolina
      that
      is affected by the Clean Smokestacks Act. In March 2007, 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 $1.1 billion to $1.4 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, and increases in the estimated inflation
      factor applied to future project costs. We are continuing to evaluate various
      design, technology, and new generation options that could further change
      expenditures required by the Clean Smokestacks Act. O&M expenses will
      significantly increase due to the cost of reagents, additional personnel and
      general maintenance associated with the 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. On March 23, 2007, PEC filed
      a
      petition with the NCUC regarding future recovery of costs to comply with the
      Clean Smokestacks Act and on October 22, 2007, PEC filed with the NCUC a
      settlement agreement with the NCUC Public Staff, CUCA and CIGFUR supporting
      PEC’s proposal. The NCUC held a hearing on this matter on October 30, 2007. See
      further discussion about the Clean Smokestacks Act in Note 4A.




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.




94


**Clean
      Air Interstate Rule, Clean Air Mercury Rule and Clean Air Visibility
      Rule**




On
      March
      10, 2005, the EPA issued the final CAIR. The EPA’s rule requires 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
      sets 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.




PEF
      has
      joined a coalition of Florida utilities that has filed a challenge to the CAIR
      as it applies to Florida. A petition for reconsideration and stay and a petition
      for judicial review of the CAIR were filed on July 11, 2005. On October 27,
      2005, the D.C. Court of Appeals issued an order granting the motion for stay
      of
      the proceedings. On December 2, 2005, the EPA announced a reconsideration of
      four aspects of the CAIR, including its applicability to Florida. On March
      16,
      2006, the EPA denied all pending reconsiderations, allowing the challenge to
      proceed. While we consider it unlikely that this challenge would eliminate
      the
      compliance requirements of the CAIR, it could potentially reduce or delay our
      costs to comply with the CAIR. On June 29, 2006, the Florida Environmental
      Regulation Commission adopted the Florida CAIR, which is very similar to the
      EPA’s model rule. An unaffiliated utility has challenged the state-adopted rule.
      The outcome of these matters cannot be predicted.




On
      March
      15, 2005, the EPA finalized two separate but related rules: the CAMR that sets
      emissions limits to be met in two phases beginning in 2010 and 2018,
      respectively, and encourages a cap-and-trade approach to achieving those caps,
      and a de-listing rule that eliminated any requirement to pursue a maximum
      achievable control technology approach for limiting mercury emissions from
      coal-fired power plants. NOx and SO2 controls
      also are
      effective in reducing mercury emissions. However, according to the EPA, the
      second phase cap reflects a level of mercury emissions reduction that exceeds
      the level that would be achieved solely as a co-benefit of controlling NOx
      and
      SO2 under CAIR.
      The de-listing rule has been challenged by a number of parties; the resolution
      of the challenges could impact our final compliance plans and costs. On October
      21, 2005, the EPA announced a reconsideration of the CAMR. On May 31, 2006,
      the
      EPA issued a determination confirming the de-listing. Sixteen states have
      subsequently petitioned for a review of this determination. The outcome of
      this
      matter cannot be predicted.




States
      were required to adopt mercury rules implementing the CAMR that are subject
      to
      review and approval by the EPA. The three states in which the Utilities operate
      have adopted mercury regulations and have submitted their state implementation
      rules to the EPA. North Carolina's rule, which was adopted on November 9, 2006,
      utilizes the EPA’s cap-and-trade approach and requires the addition of mercury
      controls by 2018 on certain of PEC's North Carolina units that do not have
      SO2 controls
      installed under the Clean Smokestacks Act. PEC has until 2013 to provide the
      North Carolina Department of Environment and Natural Resources detailed plans
      for the installation of controls at existing plants. South Carolina’s rule,
      which was adopted on January 11, 2007, utilizes the EPA’s cap-and-trade approach
      and requires that 25 percent of the mercury allowances allocated to each unit
      be
      held in a compliance supplement set-aside pool. Allowances in the set-aside
      pool
      may be used by a unit to meet compliance requirements but cannot be traded.
      The
      Florida rule, which was adopted on June 29, 2006, utilizes the EPA’s
      cap-and-trade approach with changes to the EPA’s mercury allowance allocations
      in the rule’s first phase. The EPA is currently reviewing the states’ rules. The
      outcome of this matter cannot be predicted.




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.
      To
      help restore visibility in those areas, states must require the identified
      facilities to install BART to control their emissions. Depending on the approach
      taken by the states, the reductions associated with BART would begin in 2014.
      CAVR included the EPA’s determination that compliance with the NOx and SO2 requirements
      of
      CAIR may be used by states as a BART substitute. Plans for compliance with
      CAIR
      and CAMR may fulfill BART obligations, but the states could require the
      installation of additional air quality controls if they do not achieve
      reasonable progress in improving visibility. 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 outcome of
      this
      matter cannot be predicted. On December 12, 2006, the D.C. Court of Appeals
      decided in favor of the EPA in a case brought by the National Parks Conservation
      Association that alleges the EPA acted improperly by substituting the
      requirements of CAIR for BART for NOx and SO2from electric
      generating units in areas covered by CAIR.




95


PEC
      and
      PEF are each developing an integrated compliance strategy to meet all the
      requirements of the CAIR, CAMR and CAVR. We are evaluating various design,
      technology, and new generation options that could change PEC’s and PEF’s costs
      to meet the requirements of CAIR, CAMR and CAVR.




On
      October 14, 2005, the FPSC approved PEF’s petition for the recovery of costs
      associated with the development and implementation of an integrated strategy
      to
      comply with the CAIR, CAMR and CAVR through the ECRC. 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 our Anclote and Crystal River plants. On November 6, 2006, the
      FPSC
      approved PEF’s petition for its integrated strategy to address compliance with
      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 compliance plan and associated
      contracts and recovery of costs for air pollution control projects, which
      included approximately $1.0 billion to $2.3 billion of estimated capital costs
      for the range of alternative plans. The estimated capital cost for the
      recommended plan, which was $1.26 billion in the June 1, 2007 filing, represents
      the low end of the range in the table of estimated required environmental
      expenditures shown above. The difference in costs between the recommended plan
      and the high end of the range represents the additional costs that may be
      incurred if pollution controls are required on Crystal River Units No. 1 and
      No.
      2 in order to comply with the requirements of CAVR beyond BART, should
      reasonable progress in improving visibility not be achieved, as discussed above.
      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. These costs
      will continue to change depending upon the results of the engineering and
      strategy development work and/or increases in the underlying material, labor
      and
      equipment costs. Subsequent rule interpretations, equipment availability, or
      the
      unexpected acceleration of the initial NOx or other compliance dates, among
      other things, could require acceleration of some projects. The outcome of this
      matter cannot be predicted.




**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 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.****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.




96


On
      June
      20, 2007, the EPA announced proposed changes to the NAAQS for ground-level
      ozone. The EPA proposed to lower the 8-hour primary standard from 0.08 parts
      per
      million to a range of 0.070 to 0.075 parts per million. The two alternatives
      proposed for the secondary standard are to either establish a new cumulative,
      seasonal standard or set the secondary standard as identical to the proposed
      primary standard. 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.
      The final rule is expected in March 2008. The outcome of this matter cannot
      be
      predicted.




**Water
      Quality**




1.
      General




As
      a
      result of the operation of certain control equipment needed to address the
      air
      quality issues outlined above, new wastewater streams may be generated at the
      affected facilities. Integration of these new wastewater streams into the
      existing wastewater treatment processes may result in permitting, construction
      and treatment requirements imposed on the Utilities in the immediate and
      extended future. The outcome of this matter cannot be predicted.




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
      permitting authorities establish best available technology controls for
      minimizing adverse environmental impact at existing cooling water intake
      structures on a case-by-case, best professional judgment basis. As a result
      of
      these recent 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.




3.
      North
      Carolina Groundwater Standard




On
      September 14, 2006, the North Carolina Division of Water Quality (NCDWQ)
      appeared before the North Carolina Environmental Management Commission and
      recommended the state’s groundwater quality standard for arsenic be revised to
      0.00002 milligrams/liter. The existing groundwater quality standard for arsenic
      is 0.05 milligrams/liter. The North Carolina Environmental Management Commission
      granted approval for NCDWQ staff to publish a notice in the North Carolina
      Register and schedule public hearings. Once the notice is published, the
      rulemaking process will require at least six months before the standard may
      be
      changed. Trace amounts of arsenic are commonly present in coal fly ash sluice
      water, coal pile runoff, flue gas desulphurization byproducts, and other coal
      combustion byproducts. The specific requirements of the rule as finally adopted
      and associated costs, if any, cannot be predicted.




97


**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, and the Bush administration favors
      voluntary programs. 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. 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 2007, we issued a corporate responsibility summary report, which discusses
      our actions and in 2006, we issued our report to shareholders for an assessment
      of global climate change and air quality risks and actions. 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.




In
      a
      decision issued July 15, 2005, the D.C. Court of Appeals denied petitions for
      review filed by several states, cities and organizations seeking the regulation
      by the EPA of CO2 emissions
      from new
      automobiles under the Clean Air Act, holding that the EPA administrator properly
      exercised his discretion in denying the request for regulation. The U.S. Supreme
      Court agreed to hear the case and on April 2, 2007, it ruled that the EPA has
      the authority under the Clean Air Act to regulate CO2 emissions
      from new
      automobiles. The impact of this decision cannot be predicted.




**New
      Accounting Standards**




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




98


***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 2006 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 $7 million for the nine months ended
      September 30, 2007, when compared to the corresponding period in the prior
      year.
      The increase in operating cash flow was primarily due to a $54 million increase
      in the recovery of fuel costs driven by the 2007 recovery of previously
      under-recovered fuel costs, a $31 million increase from payables to affiliates,
      and $59 million related to lower income tax extension payments. These impacts
      were partially offset by a $142 million decrease from the change in accounts
      receivable and receivables from affiliated companies. The increase from payables
      to affiliates was largely related to the timing of settlements with affiliates.
      The decrease from the change in accounts receivable was primarily due to higher
      collections in the prior year of wholesale billings and the impact of
      weather.




Cash
      used
      by investing activities increased $192 million for the nine months ended
      September 30, 2007, when compared to the corresponding period in the prior
      year,
      primarily due to a $94 million increase in capital expenditures for utility
      property additions, primarily related to an increase in spending for compliance
      with the Clean Smokestacks Act, and a $94 million increase in nuclear fuel
      additions, largely driven by an additional refueling outage in
      2007.




Net
      cash
      used by financing activities decreased $198 million for the nine months ended
      September 30, 2007, when compared to the nine months ended September 30, 2006.
      The decrease in cash used by financing activities was due primarily to PEC’s
      2007 financing activities described under Progress Energy’s MD&A, “Liquidity
      and Capital Resources” and a $147 million decrease in dividends paid to the
      Parent.




**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.




99


***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 2006 Form 10-K for a
      discussion of the factors that may impact any such forward-looking statements
      made herein.




Other
      than as discussed below, the information called for by Item 2 is omitted
      pursuant to Instruction H(2)(c) to Form 10-Q (Omission of Information by Certain
      Wholly Owned Subsidiaries).




**RESULTS
      OF OPERATIONS**




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




**LIQUIDITY
      AND CAPITAL RESOURCES**




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




Cash
      provided by operating activities increased $73 million for the nine months
      ended
      September 30, 2007, when compared to the corresponding period in the prior
      year.
      The increase was primarily due to $95 million from the change in inventory,
      $45
      million in net refunds of cash collateral previously paid to counterparties
      on
      derivative contracts in the current year compared to $52 million in net cash
      payments in the prior year, a $94 million increase from accounts payable, and
      $84 million related to lower income tax payments. The increase from inventory
      was principally driven by higher coal inventory purchases in the prior year.
      The
      increase from accounts payable was largely due to the timing of purchases and
      payments to vendors. These impacts were largely offset by a $223 million
      decrease in the recovery of fuel costs driven by the recovery of previously
      under-recovered fuel costs in the prior year and a $33 million decrease in
      payables to affiliated companies, driven by timing of settlements.




Cash
      used
      by investing activities increased $506 million for the nine months ended
      September 30, 2007, when compared to the corresponding period in the prior
      year.
      The increase in cash used by investing activities was primarily due to a $291
      million increase in capital expenditures for utility property additions, a
      $178
      million increase in net purchases of short-term investments included in
      available-for-sale securities and other investments, and a $33 million increase
      in nuclear fuel additions. The increase in utility property additions is
      primarily due to repowering the Bartow plant to more efficient natural
      gas-burning technology and environmental compliance and nuclear projects,
      partially offset by lower spending on energy system distribution projects and
      at
      the Hines Unit 4 facility. Available-for-sale securities and other investments
      include marketable debt securities and investments held in nuclear
      decommissioning trusts.




Net
      cash
      provided by financing activities was $611 million for the nine months ended
      September 30, 2007, compared to net cash used by financing activities of $326
      million for the nine months ended September 30, 2006, for a net increase of
      $937
      million. The increase in cash provided by financing activities was due primarily
      to PEF’s 2007 financing activities described under Progress Energy’s MD&A,
“Liquidity and Capital Resources” and a $176 million decrease in dividends paid
      to the Parent.




**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.




100


**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.




101


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




The
      following disclosures about market risk contain forward-looking statements
      that
      involve estimates, projections, goals, forecasts, assumptions, risks and
      uncertainties that could cause actual results or outcomes to differ materially
      from those expressed in the forward-looking statements. Please review Item
      1A,
“Risk Factors” to the 2006 Form 10-K and “Safe Harbor for Forward-Looking
      Statements” included within this Form 10-Q for a discussion of the factors that
      may impact any such forward-looking statements made herein.




Certain
      market risks are inherent in our financial instruments, which arise from
      transactions entered into in the normal course of business. Our primary
      exposures are changes in interest rates with respect to our long-term debt
      and
      commercial paper, fluctuations in the return on marketable securities with
      respect to our 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, 2006.




**INTEREST
      RATE RISK**




Our
      exposure to changes in interest rates from fixed rate and variable rate
      long-term debt at September 30, 2007, has changed from December 31, 2006. The
      total notional amount of fixed rate long-term debt at September 30, 2007, was
      $8.3 billion, with an average interest rate of 6.23% and fair market value
      of
      $8.5 billion. The total notional amount of fixed rate long-term debt at December
      31, 2006, was $7.8 billion, with an average interest rate of 6.26% and fair
      market value of $8.1 billion. The total notional amount of variable rate
      long-term debt at September 30, 2007, was $1.4 billion, with an average interest
      rate of 4.68% and fair market value of $1.4 billion. The total notional amount
      of variable rate long-term debt at December 31, 2006, was $1.4 billion, with
      an
      average interest rate of 4.47% 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 revolving credit agreement (RCA) facilities,
      which are also exposed to floating interest rates. At September 30, 2007,
      approximately 19.1 percent of consolidated debt was in floating rate mode
      compared to 15.8 percent at the end of 2006, including interest rate
      swaps.




From
      time
      to time, we use interest rate derivative instruments to adjust the mix between
      fixed and floating rate debt in our debt portfolio, to mitigate our exposure
      to
      interest rate fluctuations associated with certain debt instruments, and to
      hedge interest rates with regard to future fixed rate debt
      issuances.




The
      notional amounts of interest rate derivatives are not exchanged and do not
      represent exposure to credit loss. In the event of default by a counterparty,
      the exposure in the transaction is the cost of replacing the agreements at
      current market rates. We only enter into interest rate derivative agreements
      with banks with credit ratings of single A or better.




102


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 Statement of Financial Accounting Standards (SFAS) No. 133,
      “Accounting for Derivative 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, 2007, and December 31, 2006, the Utilities had a combined $100
      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 London Inter Bank Offering Rate (LIBOR). The Parent had no open interest
      rate cash flow hedges at September 30, 2007, and December 31, 2006.




Cash
                Flow Hedges *(dollars in millions)*
            Notional
                Amount
            Pay
            Receive
                (a)
            Fair
                Value
            Exposure
                (b)***PEC*****Risk
                hedged at September 30, 2007:****Anticipated
                10-year debt issue (c)**
            **$50**
            **5.66%**
            **3-month
                LIBOR**
            **$(2)**
            **$(1)****Anticipated
                30-year debt issue (d)**
            **50**
            **5.77%**
            **3-month
                LIBOR**
            **(2)**
            **(2)****Total**
            **$100**
            **5.72%**
            
            **$(4)**
            **$(3)**Risk
                hedged at December 31, 2006:Anticipated
                10-year debt issue (e)
            $50
            5.61%
            3-month
                LIBOR
            $(1)
            $(1)***PEF*****Risk
                hedged at September 30, 2007:**
            **None**Risk
                hedged at December 31, 2006:Anticipated
                10-year debt issue(e)
            $50
            5.61%
            3-month
                LIBOR
            $(1)
            $(1)


(a)
            3-month
                LIBOR rate was 5.23% at September 30, 2007, and 5.36% at December
                31,
                2006.


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


(c)
            Anticipated
                10-year debt issue hedge mature on April 1, 2018, and require mandatory
                cash settlement on April 1, 2008.


(d)
            Anticipated
                30-year debt issue hedge matures on April 1, 2038, and requires mandatory
                cash settlement on April 1, 2008.


(e)
            Anticipated
                10-year debt issue hedges matured on October 1, 2017, and required
                mandatory cash settlement on October 1,
                2007.





Subsequent
      to December 31, 2006, PEF had entered into a combined $225 million notional
      of
      forward starting swaps to mitigate exposure to interest rate risk in
      anticipation of future debt issuances, which were terminated on September 13,
      2007, in conjunction with PEF’s issuance of $500 million of First Mortgage
      Bonds, 6.35% Series due 2037 and $250 million of First Mortgage Bonds, 5.80%
      Series due 2017. On July 30, 2007, PEC entered into a $50 million notional
      forward starting swap to mitigate exposure to interest rate risk in anticipation
      of future debt issuances. On September 25, 2007, PEC amended its 10-year forward
      starting swap in order to move the maturity date from October 1, 2017 to April
      1, 2018.




103


On
      October 24, 2007, PEC entered into $100 million notional of forward starting
      swaps to mitigate exposure to interest rate risk in anticipation of future
      debt
      issuances.




**Fair
      Value Hedges**




At
      December 31, 2006, the Parent had $50 million notional of fixed rate debt
      swapped to floating rate debt, which was terminated on September 26, 2007.
      Under
      terms of these swap agreements, we received a fixed rate and paid a floating
      rate based on 3-month LIBOR. At September 30, 2007, and December 31, 2006,
      the
      Utilities had no open interest rate fair value hedges.




Fair
                Value Hedges*(dollars in millions)*
            Notional
                Amount
            Receive
            Pay(a)
            Fair
                Value
            Exposure(b)***Progress
                Energy*****Risk
                hedged at September 30, 2007**
            **None**Risk
                hedged at December 31, 20067.10%
                Notes due 3/1/2011
            $50
            4.65%
            3-month
                LIBOR
            $(1)
            $–


(a)      3-month
      LIBOR rate was 5.36% at December 31, 2006.


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





**MARKETABLE
      SECURITIES PRICE RISK**




At
      September 30, 2007, and December 31, 2006, the fair value of our nuclear
      decommissioning trust funds was $1.358 billion and $1.287 billion, respectively,
      including $782 million and $735 million, respectively, for PEC and $576 million
      and $552 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.




**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, 2007, and December 31, 2006,
      the fair value of CVOs was $34 million and $32 million, respectively. A
      hypothetical 10 percent decrease in the September 30, 2007, market price would
      result in a $3 million decrease 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. We also
      have
      oil price risk exposure related to synthetic fuels tax credits as discussed
      in
“Other Matters – Synthetic Fuels Tax Credits” of Item 2.




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




As
      discussed in Note 3A, our subsidiary, PVI, entered into a series of transactions
      to sell substantially all of its CCO physical and commercial assets and
      liabilities. On June 1, 2007, PVI closed the transaction involving the
      assignment of a contract portfolio consisting of 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. The sale of the generation
      assets closed on June 11, 2007. Additionally, we sold




104


Gas
      on
      October 2, 2006 (See Note 3B). Due to these divestitures, management determined
      that it was no longer probable that the forecasted transactions underlying
      certain derivative contracts would be fulfilled and cash flow hedge accounting
      for the contracts was discontinued beginning in the second quarter of 2006
      for
      Gas and fourth quarter of 2006 for CCO.




At
      September 30, 2007, due to the closing of the transactions discussed above,
      our
      discontinued operations did not have outstanding positions in derivative
      instruments. At December 31, 2006, derivative assets of $107 million were
      included in assets of discontinued operations and derivative liabilities of
      $31
      million were included in liabilities of discontinued operations on the
      Consolidated Balance Sheet. For the three months ended September 30, 2007,
      there
      were no material net gains and losses from derivative instruments included
      in
      discontinued operations on the Consolidated Statements of Income. For the nine
      months ended September 30, 2007, after-tax gains from derivative instruments
      of
      $88 million were included in discontinued operations on the Consolidated
      Statements of Income. For the three and nine months ended September 30, 2006,
      after-tax losses from derivative instruments of $30 million and $39 million,
      respectively, were included in discontinued operations on the Consolidated
      Statements of Income. For the three and nine months ended September 30, 2007,
      there were no reclassifications to earnings due to the discontinuance of the
      related cash flow hedges. For the three months ended September 30, 2006, there
      were no reclassifications to earnings due to the discontinuance of the related
      cash flow hedges. For the nine months ended September 30, 2006, $7 million
      in
      after-tax losses were reclassified to earnings due to the discontinuance of
      the
      related cash flow hedges in anticipation of the sale of Gas.




We
      perform sensitivity analyses to estimate our exposure to the market risk of
      our
      derivative commodity instruments that are not eligible for recovery from
      ratepayers. The following discussion addresses the stand-alone commodity risk
      created by these derivative commodity instruments, without regard to the
      offsetting effect of the underlying exposure these instruments are intended
      to
      hedge. The sensitivity analysis performed on these derivative commodity
      instruments uses quoted prices obtained from brokers to measure the potential
      loss in earnings from a hypothetical 10 percent adverse change in market prices
      over the next 12 months. At September 30, 2007, derivative commodity instruments
      not eligible for recovery from ratepayers related to derivative contracts
      entered into on January 8, 2007, to hedge economically a portion of our 2007
      synthetic fuels cash flow exposure to the risk of rising oil prices as discussed
      under “Economic Derivatives” below. A decrease of 10 percent in the market
      prices of energy commodities from their September 30, 2007, levels would
      decrease after-tax earnings by approximately $18 million. At December 31, 2006,
      derivative commodity instruments not eligible for recovery from ratepayers
      are
      included in discontinued operations.




The
      above
      analysis of our derivative commodity instruments used for hedging purposes
      does
      not include the potential favorable impact of the same hypothetical price
      movement on the value of synthetic fuels tax credits to which the hedges relate.
      Additionally, our derivative commodity portfolio is managed to complement the
      physical transaction portfolio, reducing overall risk within set limits.
      Therefore, the potential impact to earnings from a hypothetical 10 percent
      adverse change in commodity market prices would be offset by a favorable impact
      on the underlying hedged physical transactions, assuming the derivative
      commodity positions are not closed out in advance of their expected term,
      continue to function effectively as hedges of the underlying risk, and the
      anticipated underlying transactions settle, as applicable. If any of these
      assumptions ceases to be true, a loss on the derivative instruments may
      occur.




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




**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.




On
      January 8, 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




105


instruments
      is 25 million barrels and will provide 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 are marked-to-market
      with changes in fair value recorded through earnings from synthetic fuels
      production. Approximately 34 percent of the notional quantity of these contracts
      was entered into by Ceredo. As discussed in Notes 1C and 3I, we disposed of
      our
      100 percent ownership interest in Ceredo on March 30, 2007. Progress Energy
      is
      the primary beneficiary of, and continues to consolidate Ceredo in accordance
      with FIN 46R, but we have recorded a 100 percent minority interest.
      Consequently, subsequent to the disposal there is no net earnings impact for
      the
      contracts entered into by Ceredo. At September 30, 2007, the fair value of
      these
      contracts was recorded as a $170 million short-term derivative asset position,
      including $58 million at Ceredo. The fair value of these contracts was included
      in derivative assets on the Consolidated Balance Sheet. During the three and
      nine months ended September 30, 2007, we recorded net pre-tax gains of $74
      million and $105 million, respectively, in diversified business revenues related
      to these contracts, including net pre-tax gains of $26 million and $21 million,
      respectively, at Ceredo subsequent to disposal of our 100 percent ownership
      interest.




The
      Utilities have derivative instruments related to their exposure to price
      fluctuations on fuel oil and natural gas purchases. These instruments receive
      regulatory accounting treatment. 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.




At
      September 30, 2007, the fair value of PEC’s commodity derivative instruments was
      recorded as a $3 million long-term derivative asset position included in other
      assets and deferred debits and a $5 million short-term derivative liability
      position included in other current liabilities on the Consolidated Balance
      Sheet. At December 31, 2006, PEC did not have material outstanding positions
      in
      such contracts.




At
      September 30, 2007, the fair value of PEF’s commodity derivative instruments was
      recorded as a $14 million short-term derivative asset position included in
      prepayments and other current assets, a $12 million long-term derivative asset
      position included in other assets and deferred debits, a $31 million short-term
      derivative liability position included in derivative liabilities, and a $5
      million long-term derivative liability position included in other liabilities
      and deferred credits on the PEF Balance Sheet. At December 31, 2006, the fair
      value of such instruments was recorded as a $2 million long-term derivative
      asset position included in other assets and deferred debits, an $87 million
      short-term derivative liability position included in derivative liabilities
      and
      a $36 million long-term derivative liability position included in other
      liabilities and deferred credits on the PEF Balance Sheet.




**Cash
      Flow Hedges**




Our
      subsidiaries designate 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
      natural gas and power for our forecasted purchases and sales. Realized gains
      and
      losses are recorded net in operating revenues or operating expenses, as
      appropriate. At September 30, 2007, and December 31, 2006, we and the Utilities
      did not have material outstanding positions in such contracts. The ineffective
      portion of commodity cash flow hedges for the three and nine months ended
      September 30, 2007 and 2006, was not material to our or the Utilities’ results
      of operations.




Our
      discontinued operations did not have material outstanding positions in commodity
      cash flow hedges at September 30, 2007, or December 31, 2006.




***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, 2006.




106


***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.




There
      has
      been no change in our internal control over financial reporting during the
      quarter ended September 30, 2007, that has materially affected, or is reasonably
      likely to materially affect, our internal control over financial
      reporting.




***PEC***




Pursuant
      to the Securities Exchange Act of 1934, PEC carried out an evaluation, with
      the
      participation of its management, including PEC’s Chief Executive Officer and
      Chief Financial Officer, of the effectiveness of PEC’s disclosure controls and
      procedures (as defined under the Securities Exchange Act of 1934) as of the
      end
      of the period covered by this report. Based upon that evaluation, PEC’s Chief
      Executive Officer and Chief Financial Officer concluded that its disclosure
      controls and procedures are effective to ensure that information required to
      be
      disclosed by PEC in the reports that it files or submits under the Exchange
      Act,
      is recorded, processed, summarized and reported within the time periods
      specified in the SEC's rules and forms, and that such information is accumulated
      and communicated to PEC’s management, including the Chief Executive Officer and
      Chief Financial Officer, as appropriate, to allow timely decisions regarding
      required disclosure.




There
      has
      been no change in PEC’s internal control over financial reporting during the
      quarter ended September 30, 2007, that has materially affected, or is reasonably
      likely to materially affect, its internal control over financial
      reporting.




***PEF***




Pursuant
      to the Securities Exchange Act of 1934, PEF carried out an evaluation, and
      with
      the participation of its management, including PEF’s Chief Executive Officer and
      Chief Financial Officer, of the effectiveness of PEF’s disclosure controls and
      procedures (as defined under the Securities Exchange Act of 1934) as of the
      end
      of the period covered by this report. Based upon that evaluation, PEF’s Chief
      Executive Officer and Chief Financial Officer concluded that its disclosure
      controls and procedures are effective to ensure that information required to
      be
      disclosed by PEF in the reports that it files or submits under the Exchange
      Act,
      is recorded, processed, summarized and reported within the time periods
      specified in the SEC's rules and forms, and that such information is accumulated
      and communicated to PEF’s management, including the Chief Executive Officer and
      Chief Financial Officer, as appropriate, to allow timely decisions regarding
      required disclosure.




There
      has
      been no change in PEF’s internal control over financial reporting during the
      quarter ended September 30, 2007, that has materially affected, or is reasonably
      likely to materially affect, its internal control over financial
      reporting.




107





**PART
      II.  OTHER INFORMATION**





Item
      1.                      Legal
      Proceedings




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







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 2006
      Form
      10-K, which could materially affect our business, financial condition or future
      results. The risks described in the 2006 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
      2007 divestiture of the physical and commercial assets of CCO, we are no longer
      subject to risks from operating nonregulated plants or engaging in nonregulated
      energy marketing and trading activities as disclosed in the 2006 Form
      10-K.







Item
      2.                      Unregistered
      Sale of Equity Securities and Use of Proceeds




**RESTRICTED
      STOCK UNIT AWARD PAYOUTS**




(a)
            Securities
                Delivered. On July 2, 2007, July 5, 2007, July 19, 2007 and September
                26, 2007, 4,584 shares, 1,944 shares, 87 shares and 3,433 shares,
                respectively, of our common stock were delivered to certain former
                employees pursuant to the terms of the Progress Energy 2002 Equity
                Incentive Plan (EIP), which was approved by the Progress Energy’s
                shareholders on May 8, 2002. The shares of common stock delivered
                pursuant
                to the EIP were newly issued shares of Progress
                Energy.





(b)
            Underwriters
                and Other Purchasers. No underwriters were used in connection with the
                delivery of our common stock described
                above.





(c)
            Consideration.
                The restricted stock unit awards were granted to provide an incentive
                to
                the former employees to exert their utmost efforts on Progress Energy’s
                behalf and thus enhance our performance while aligning the employees’
                interest with those of our
                shareholders.





(d)
            Exemption
                from Registration Claimed. The common shares described in this Item
                were delivered pursuant to a broad-based involuntary, non-contributory
                employee benefit plan, and thus did not involve an offer to sell
                or sale
                of securities within the meaning of Section 2(3) of the Securities
                Act of
                1933. Receipt of the shares of our common stock required no investment
                decision on the part of the
                recipient.







108


**Issuer
      Purchases of Equity Securities for Third Quarter of
      2007**




**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
            229,612
            $45.1534
            N/A
            N/AAugust
                1 - August 31
            58,500
            44.7313
            N/A
            N/ASeptember
                1 - September 30
            –
            –
            N/A
            N/ATotal
            288,112
            $44.9424
            N/A
            N/A





(1)
            As
                of September 30, 2007, Progress Energy does not have any publicly
                announced plans or programs to purchase shares of its common
                stock.


(2)
            The
                plan administrator purchased 288,112 shares of our common stock in
                open-market transactions to meet share delivery obligations under
                our
                401(k).








Item
      6.                      Exhibits




(a)
            Exhibits





Exhibit
                Number
            Description
            Progress
              Energy
            PEC
            PEF31(a)
            302
                Certifications of Chief Executive Officer
            X31(b)
            302
                Certifications of Chief Financial Officer
            X31(c)
            302
                Certifications of Chief Executive Officer
            
            X31(d)
            302
                Certifications of Chief Financial Officer
            
            X31(e)
            302
                Certifications of Chief Executive Officer
            
            
            X31(f)
            302
                Certifications of Chief Financial Officer
            
            
            X32(a)
            906
                Certifications of Chief Executive Officer
            X32(b)
            906
                Certifications of Chief Financial Officer
            X32(c)
            906
                Certifications of Chief Executive Officer
            
            X32(d)
            906
                Certifications of Chief Financial Officer
            
            X32(e)
            906
                Certifications of Chief Executive Officer
            
            
            X32(f)
            906
                Certifications of Chief Financial Officer
            
            
            X





109





SIGNATURES




Pursuant
      to requirements of the Securities Exchange Act of 1934, the registrant has
      duly
      caused this report to be signed on its behalf by the undersigned thereunto
      duly
      authorized.




PROGRESS
                ENERGY, INC.CAROLINA
                POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS,
                INC.FLORIDA
                POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA, INC.Date:
                November 5, 2007
            (Registrants)By:
                /s/ Peter M. Scott IIIPeter
                M. Scott IIIExecutive
                Vice President and Chief Financial OfficerBy:
                /s/ Jeffrey M. StoneJeffrey
                M. StoneChief
                Accounting Officer and ControllerProgress
                Energy, Inc.Chief
                Accounting OfficerCarolina
                Power & Light Company d/b/a Progress Energy Carolinas,
                Inc.Florida
                Power Corporation d/b/a Progress Energy Florida,
                Inc.





110