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 March
      31, 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 NumberCorporate Logo1-15929
            **Progress
                Energy, Inc.**
              410
                South Wilmington Street
              Raleigh,
                North Carolina 27601-1748
              Telephone:
                (919) 546-6111
              State
                of Incorporation: North Carolina
            56-21554811-3382
            **Carolina
                Power & Light Company**
              **d/b/a
                Progress Energy Carolinas, Inc.**
              410
                South Wilmington Street
              Raleigh,
                North Carolina 27601-1748
              Telephone:
                (919) 546-6111
              State
                of Incorporation: North Carolina
            56-01654651-3274
            **Florida
                Power Corporation**
              **d/b/a
                Progress Energy Florida, Inc.**
              299
                First Avenue North
              St.
                Petersburg, Florida 33701
              Telephone:
                (727) 820-5151
              State
                of Incorporation: Florida
            59-0247770





NONE


(Former
      name, former address and former fiscal year, if changed since last
      report)





Indicate
      by check mark whether each registrant (1) has filed all reports required to
      be
      filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
      the
      preceding 12 months (or for such shorter period that the registrants were
      required to file such reports), and (2) has been subject to such filing
      requirements for the past 90 days.





Progress
                Energy, Inc. (Progress Energy)
            Yes
            x
            No
            oCarolina
                Power & Light Company (PEC)
            Yes
            x
            No
            oFlorida
                Power Corporation (PEF)
            Yes
            o
            No
            x


1





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
      April 30, 2007, each registrant had the following shares of common stock
      outstanding:





**Registrant**
            **Description**
            **Shares**Progress
                Energy
            Common
                Stock (Without Par Value)
            257,861,484PEC
            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 IncomeUnaudited
                Consolidated Balance SheetsUnaudited
                Consolidated Statements of Cash FlowsCarolina
                Power & Light Companyd/b/a
                Progress Energy Carolinas, Inc. (PEC)Unaudited
                Consolidated Statements of IncomeUnaudited
                Consolidated Balance SheetsUnaudited
                Consolidated Statements of Cash FlowsFlorida
                Power Corporationd/b/a
                Progress Energy Florida, Inc. (PEF)Unaudited
                Statements of IncomeUnaudited
                Balance SheetsUnaudited
                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
                5.
            Other
                Information




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 LLCClean
                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
                and Synthetic Fuels
            Business
                segment primarily engaged in synthetic fuels production and sales
                operations, 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
                coal-fired steam turbines Crystal River Units No. 4 and
                5CUCA
            Carolina
                Utility Customers AssociationCVO
            Contingent
                value obligationD.C.
                Circuit Court
            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 EnergyEarthco
            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 AgencyEnergy
                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 CommissionFGT
            Florida
                Gas Transmission CompanyFIN
                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 CommissionFunding
                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 serviced by CCOGeorgia
                Power
            Georgia
                Power Company, a subsidiary of Southern CompanyGeorgia
                Region
            Reporting
                unit consisting of our Effingham, Monroe, Walton and Washington
                nonregulated generation plants in serviceGlobal
            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-QMedicare
                Act
            Medicare
                Prescription Drug, Improvement and Modernization Act of
                2003MGP
            Manufactured
                gas plantMW
            MegawattsMWh
            Megawatt-hoursMoody’s
            Moody’s
                Investors Service, Inc.NAAQS
            National
                Ambient Air Quality StandardsNCDWQ
            North
                Carolina Division of Water QualityNCNG
            North
                Carolina Natural Gas Corporation




5


NCUC
            North
                Carolina Utilities CommissionNEIL
            Nuclear
                Electric Insurance LimitedNERC
            North
                American Electric Reliability
                Council


NOPR
            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
                OxideNOx
                SIP Call
            EPA
                rule which requires 22 states including North Carolina, South Carolina
                and
                Georgia (but excluding Florida) to further reduce nitrogen oxide
                emissionsNSR
            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 expenseOCI
            Other
                comprehensive incomeOPC
            Florida’s
                Office of Public CounselOPEB
            Postretirement
                benefits other than pensionsthe
                Parent
            Progress
                Energy, Inc. holding company on an unconsolidated basisPEC
            Progress
                Energy Carolinas, Inc., formerly referred to as Carolina Power & Light
                CompanyPEF
            Progress
                Energy Florida, Inc., formerly referred to as Florida Power
                CorporationPESC
            Progress
                Energy Service Company, LLCthe
                Phase-out Price
            Price
                per barrel of unregulated domestic crude oil at which the value of
                Section
                29/45K tax credits are fully eliminatedPM
                2.5
            EPA
                standard for particulate matter less than 2.5 microns in
                diameterPM
                2.5-10
            EPA
                standard for particulate matter between 2.5 and 10 microns in
                diameterPM
                10
            EPA
                standard for particulate matter less than 10 microns in
                diameterPower
                Agency
            North
                Carolina Eastern Municipal Power AgencyPreferred
                Securities
            7.10%
                Cumulative Quarterly Income Preferred Securities due 2039, Series
                A issued
                by the TrustPreferred
                Securities Guarantee
            Florida
                Progress’ guarantee of all distributions related to the Preferred
                SecuritiesProgress
                Affiliates
            Five
                affiliated 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 CorporationPT
                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 agreementRockport
            Indiana
                Michigan Power Company’s Rockport Unit No. 2Robinson
            PEC’s
                Robinson Nuclear PlantROE
            Return
                on equity




6


Rowan
            Rowan
                County Power, LLCRSA
            Restricted
                stock awards programRTO
            Regional
                transmission organizationSCPSC
            Public
                Service Commission of South
                Carolina


Scrubber
            A
                device that neutralizes sulfur compounds formed during coal
                combustionSEC
            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-QSESH
            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”SNG
            Southern
                Natural Gas CompanySO2
            Sulfur
                dioxideSubordinated
                Notes
            7.10%
                Junior Subordinated Deferrable Interest Notes due 2039 issued by
                Funding
                Corp.Tax
                Agreement
            Intercompany
                Income Tax Allocation 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.


7


**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, baseload expansion and the effects of new
      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; 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 commercial and industrial customers; 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 2008; our ability to generate and
      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 execution of our announced transactions to
      dispose of our Competitive Commercial Operations (CCO) business and additional
      resulting charges to income, which could exceed $320 million after-tax; our
      ability to manage the risks involved with the CCO business, including dependence
      on third parties and related counterparty risks, until completion of our
      divestiture transactions; 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.




8


PART
      I.
      FINANCIAL INFORMATION


Item
      1 .  Financial
      Statements





**PROGRESS
      ENERGY, INC.**


**CONSOLIDATED
      INTERIM FINANCIAL STATEMENTS**


**March
      31, 2007**





**UNAUDITED
                CONSOLIDATED STATEMENTS of INCOME***(in
                millions, except per share data)*Three
                Months Ended March 31
            
            **2007**
            
            2006**Operating
                revenues**Electric
            
            **$**
            **2,068**
            
            $
            1,985Diversified
                business
            
            
            **266**
            
            
            238**Total
                operating revenues**
            
            
            **2,334**
            
            
            2,223**Operating
                expenses**UtilityFuel
                used in electric generation
            
            
            **736**
            
            
            690Purchased
                power
            
            
            **221**
            
            
            229Operation
                and maintenance
            
            
            **420**
            
            
            416Depreciation
                and amortization
            
            
            **219**
            
            
            228Taxes
                other than on income
            
            
            **124**
            
            
            119Other
            
            
            **(1**
            **)**
            
            (2
            )Diversified
                businessCost
                of sales
            
            
            **244**
            
            
            256Depreciation
                and amortization
            
            
            **2**
            
            
            9Gain
                on the sales of assets
            
            
            **(16**
            **)**
            
            (4
            )Other
            
            
            **18**
            
            
            14**Total
                operating expenses**
            
            
            **1,967**
            
            
            1,955**Operating
                income**
            
            
            **367**
            
            
            268**Other
                income (expense)**Interest
                income
            
            
            **8**
            
            
            17Other,
                net
            
            
            **9**
            
            
            (2
            )**Total
                other income**
            
            
            **17**
            
            
            15**Interest
                charges**Net
                interest charges
            
            
            **144**
            
            
            165Allowance
                for borrowed funds used during construction
            
            
            **(3**
            **)**
            
            (2
            )**Total
                interest charges, net**
            
            
            **141**
            
            
            163**Income
                from continuing operations before income tax and minority
                interest**
            
            
            **243**
            
            
            120**Income
                tax expense**
            
            
            **19**
            
            
            29**Income
                from continuing operations before minority interest**
            
            
            **224**
            
            
            91**Minority
                interest in subsidiaries’ income, net of tax**
            
            
            **4**
            
            
            6**Income
                from continuing operations**
            
            
            **220**
            
            
            85**Discontinued
                operations, net of tax**
            
            
            **55**
            
            
            (40
            )**Net
                income**
            
            **$**
            **275**
            
            $
            45**Average
                common shares outstanding - basic**
            
            
            **254**
            
            
            249**Basic
                earnings per common share**Income
                from continuing operations
            
            **$**
            **0.87**
            
            $
            0.34Discontinued
                operations, net of tax
            
            
            **0.21**
            
            
            (0.16
            )Net
                income
            
            **$**
            **1.08**
            
            $
            0.18**Diluted
                earnings per common share**Income
                from continuing operations
            
            **$**
            **0.87**
            
            $
            0.34Discontinued
                operations, net of tax
            
            
            **0.21**
            
            
            (0.16
            )Net
                income
            
            **$**
            **1.08**
            
            $
            0.18**Dividends
                declared per common share**
            
            **$**
            **0.610**
            
            $
            0.605





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


9




PROGRESS ENERGY, INC.  **UNAUDITED
                  CONSOLIDATED BALANCE SHEETS***(in
                  millions)*
              
              **March
                  31, 2007**
              
              December
                  31, 2006**ASSETS****Utility
                  plant**Utility
                  plant in service
              
              **$**
              **23,865**
              
              $
              23,743Accumulated
                  depreciation
              
              
              **(10,152**
              **)**
              
              (10,064
              )Utility
                  plant in service, net
              
              
              **13,713**
              
              
              13,679Held
                  for future use
              
              
              **10**
              
              
              10Construction
                  work in progress
              
              
              **1,526**
              
              
              1,289Nuclear
                  fuel, net of amortization
              
              
              **300**
              
              
              267**Total
                  utility plant, net**
              
              
              **15,549**
              
              
              15,245**Current
                  assets**Cash
                  and cash equivalents
              
              
              **133**
              
              
              265Short-term
                  investments
              
              
              **1**
              
              
              71Receivables,
                  net
              
              
              **960**
              
              
              930Inventory
              
              
              **1,013**
              
              
              969Deferred
                  fuel cost
              
              
              **189**
              
              
              196Deferred
                  income taxes
              
              
              **17**
              
              
              159Assets
                  of discontinued operations
              
              
              **895**
              
              
              887Derivative
                  assets
              
              
              **112**
              
              
              1Prepayments
                  and other current assets
              
              
              **68**
              
              
              107**Total
                  current assets**
              
              
              **3,388**
              
              
              3,585**Deferred
                  debits and other assets**Regulatory
                  assets
              
              
              **1,104**
              
              
              1,231Nuclear
                  decommissioning trust funds
              
              
              **1,307**
              
              
              1,287Diversified
                  business property, net
              
              
              **30**
              
              
              31Miscellaneous
                  other property and investments
              
              
              **456**
              
              
              456Goodwill
              
              
              **3,655**
              
              
              3,655Other
                  assets and deferred debits
              
              
              **230**
              
              
              211**Total
                  deferred debits and other assets**
              
              
              **6,782**
              
              
              6,871**Total
                  assets**
              
              **$**
              **25,719**
              
              $
              25,701**CAPITALIZATION
                  AND LIABILITIES****Common
                  stock equity**Common
                  stock without par value, 500 million shares authorized, 258 and
                  256
                  million shares issued and outstanding, respectively
              
              **$**
              **5,882**
              
              $
              5,791Unearned
                  ESOP shares (2 million shares)
              
              
              **(42**
              **)**
              
              (50
              )Accumulated
                  other comprehensive loss
              
              
              **(50**
              **)**
              
              (49
              )Retained
                  earnings
              
              
              **2,711**
              
              
              2,594**Total
                  common stock equity**
              
              
              **8,501**
              
              
              8,286**Preferred
                  stock of subsidiaries - not subject to mandatory
                  redemption**
              
              
              **93**
              
              
              93**Minority
                  interest**
              
              
              **54**
              
              
              10**Long-term
                  debt, affiliate**
              
              
              **271**
              
              
              271**Long-term
                  debt, net**
              
              
              **8,512**
              
              
              8,564**Total
                  capitalization**
              
              
              **17,431**
              
              
              17,224**Current
                  liabilities**Current
                  portion of long-term debt
              
              
              **404**
              
              
              324Short-term
                  debt
              
              
              **117**
              
              
              **-**Accounts
                  payable
              
              
              **652**
              
              
              712Interest
                  accrued
              
              
              **139**
              
              
              171Dividends
                  declared
              
              
              **157**
              
              
              156Customer
                  deposits
              
              
              **236**
              
              
              227Liabilities
                  of discontinued operations
              
              
              **179**
              
              
              189Income
                  taxes accrued
              
              
              **44**
              
              
              284Other
                  current liabilities
              
              
              **692**
              
              
              755**Total
                  current liabilities**
              
              
              **2,620**
              
              
              2,818**Deferred
                  credits and other liabilities**Noncurrent
                  income tax liabilities
              
              
              **270**
              
              
              306Accumulated
                  deferred investment tax credits
              
              
              **148**
              
              
              151Regulatory
                  liabilities
              
              
              **2,584**
              
              
              2,543Asset
                  retirement obligations
              
              
              **1,321**
              
              
              1,306Accrued
                  pension and other benefits
              
              
              **964**
              
              
              957Other
                  liabilities and deferred credits
              
              
              **381**
              
              
              396**Total
                  deferred credits and other liabilities**
              
              
              **5,668**
              
              
              5,659**Commitments
                  and contingencies (Notes 11 and 12)****Total
                  capitalization and liabilities**
              
              **$**
              **25,719**
              
              $
              25,701
 *See
        Notes to Progress Energy, Inc. Consolidated Interim Financial
        Statements.*


10


PROGRESS
      ENERGY, INC.


**UNAUDITED
                CONSOLIDATED STATEMENTS of CASH FLOWS***(in
                millions)*Three
                Months Ended March 31
            
            **2007**
            
            2006**Operating
                activities**Net
                income
            
            **$**
            **275**
            
            $
            45Adjustments
                to reconcile net income to net cash provided by operating
                activitiesDiscontinued
                operations, net of tax
            
            
            **(55**
            **)**
            
            40Depreciation
                and amortization
            
            
            **250**
            
            
            267Deferred
                income taxes
            
            
            **106**
            
            
            34Investment
                tax credits
            
            
            **(3**
            **)**
            
            (3
            )Tax
                levelization
            
            
            **(8**
            **)**
            
            16Deferred
                fuel cost
            
            
            **108**
            
            
            134Other
                adjustments to net income
            
            
            **12**
            
            
            75Cash
                provided (used) by changes in operating assets and
                liabilitiesReceivables
            
            
            **59**
            
            
            123Inventory
            
            
            **(36**
            **)**
            
            (60
            )Prepayments
                and other current assets
            
            
            **(74**
            **)**
            
            (15
            )Accounts
                payable
            
            
            **(51**
            **)**
            
            (78
            )Other
                current liabilities
            
            
            **(290**
            **)**
            
            (172
            )Regulatory
                assets and liabilities
            
            
            **8**
            
            
            (2
            )Other
                liabilities and deferred credits
            
            
            **(11**
            **)**
            
            22Other
                assets and deferred debits
            
            
            **(21**
            **)**
            
            16**Net
                cash provided by operating activities**
            
            
            **269**
            
            
            442**Investing
                activities**Gross
                utility property additions
            
            
            **(469**
            **)**
            
            (304
            )Nuclear
                fuel additions
            
            
            **(61**
            **)**
            
            (52
            )Proceeds
                from sales of discontinued operations and other assets, net of cash
                divested
            
            
            **30**
            
            
            103Purchases
                of available-for-sale securities and other investments
            
            
            **(192**
            **)**
            
            (538
            )Proceeds
                from sales of available-for-sale securities and other
                investments
            
            
            **252**
            
            
            522Other
                investing activities
            
            
            **(1**
            **)**
            
            (11
            )**Net
                cash used by investing activities**
            
            
            **(441**
            **)**
            
            (280
            )**Financing
                activities**Issuance
                of common stock
            
            
            **65**
            
            
            28Proceeds
                from issuance of long-term debt, net
            
            
            **-**
            
            
            397Net
                increase in short-term debt
            
            
            **117**
            
            
            79Retirement
                of long-term debt
            
            
            **-**
            
            
            (801
            )Dividends
                paid on common stock
            
            
            **(155**
            **)**
            
            (151
            )Other
                financing activities
            
            
            **(33**
            **)**
            
            (60
            )**Net
                cash used by financing activities**
            
            
            **(6**
            **)**
            
            (508
            )**Cash
                provided (used) by discontinued operations**Operating
                activities
            
            
            **47**
            
            
            54Investing
                activities
            
            
            **(1**
            **)**
            
            (50
            )Financing
                activities
            
            
            **-**
            
            
            -**Net
                decrease in cash and cash equivalents**
            
            
            **(132**
            **)**
            
            (342
            )**Cash
                and cash equivalents at beginning of period**
            
            
            **265**
            
            
            605**Cash
                and cash equivalents at end of period**
            
            **$**
            **133**
            
            $
            263





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


11


**CAROLINA
      POWER & LIGHT COMPANY**


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


**CONSOLIDATED
      INTERIM FINANCIAL STATEMENTS**


**March
      31, 2007**





**UNAUDITED
                CONSOLIDATED STATEMENTS of INCOME***(in
                millions)*Three
                Months Ended March 31
            
            **2007**
            
            2006**Operating
                revenues**Electric
            
            **$**
            **1,057**
            
            $
            978Diversified
                business
            
            
            **1**
            
            
            -**Total
                operating revenues**
            
            
            **1,058**
            
            
            978**Operating
                expenses**Fuel
                used in electric generation
            
            
            **351**
            
            
            296Purchased
                power
            
            
            **58**
            
            
            64Operation
                and maintenance
            
            
            **248**
            
            
            256Depreciation
                and amortization
            
            
            **117**
            
            
            126Taxes
                other than on income
            
            
            **50**
            
            
            46Other
            
            
            **(1**
            **)**
            
            1**Total
                operating expenses**
            
            
            **823**
            
            
            789**Operating
                income**
            
            
            **235**
            
            
            189**Other
                income (expense)**Interest
                income
            
            
            **6**
            
            
            7Other,
                net
            
            
            **3**
            
            
            (1
            )**Total
                other income**
            
            
            **9**
            
            
            6**Interest
                charges**Interest
                charges
            
            
            **57**
            
            
            57Allowance
                for borrowed funds used during construction
            
            
            **(1**
            **)**
            
            (1
            )**Total
                interest charges, net**
            
            
            **56**
            
            
            56**Income
                before income tax**
            
            
            **188**
            
            
            139**Income
                tax expense**
            
            
            **64**
            
            
            53**Net
                income**
            
            
            **124**
            
            
            86**Preferred
                stock dividend requirement**
            
            
            **1**
            
            
            1**Earnings
                for common stock**
            
            **$**
            **123**
            
            $
            85





*See
      Notes to PEC Consolidated Interim Financial Statements.*


12


CAROLINA
      POWER & LIGHT COMPANY


d/b/a
      PROGRESS ENERGY CAROLINAS, INC.


**UNAUDITED
                CONSOLIDATED BALANCE SHEETS***(in
                millions)*
            
            **March
                31, 2007**
            
            December
                31, 2006**ASSETS****Utility
                plant**Utility
                plant in service
            
            **$**
            **14,423**
            
            $
            14,356Accumulated
                depreciation
            
            
            **(6,459**
            **)**
            
            (6,408
            )Utility
                plant in service, net
            
            
            **7,964**
            
            
            7,948Held
                for future use
            
            
            **3**
            
            
            3Construction
                work in progress
            
            
            **711**
            
            
            617Nuclear
                fuel, net of amortization
            
            
            **225**
            
            
            209**Total
                utility plant, net**
            
            
            **8,903**
            
            
            8,777**Current
                assets**Cash
                and cash equivalents
            
            
            **81**
            
            
            71Short-term
                investments
            
            
            **1**
            
            
            50Receivables,
                net
            
            
            **448**
            
            
            473Receivables
                from affiliated companies
            
            
            **20**
            
            
            27Note
                receivable from affiliated company
            
            
            **-**
            
            
            24Inventory
            
            
            **513**
            
            
            497Deferred
                fuel cost
            
            
            **185**
            
            
            196Prepayments
                and other current assets
            
            
            **9**
            
            
            45**Total
                current assets**
            
            
            **1,257**
            
            
            1,383**Deferred
                debits and other assets**Regulatory
                assets
            
            
            **755**
            
            
            777Nuclear
                decommissioning trust funds
            
            
            **749**
            
            
            735Miscellaneous
                other property and investments
            
            
            **187**
            
            
            193Other
                assets and deferred debits
            
            
            **142**
            
            
            155**Total
                deferred debits and other assets**
            
            
            **1,833**
            
            
            1,860**Total
                assets**
            
            **$**
            **11,993**
            
            $
            12,020**CAPITALIZATION
                AND LIABILITIES****Common
                stock equity**Common
                stock without par value, authorized 200 million shares, 160 million
                shares
                issued and outstanding
            
            **$**
            **2,024**
            
            $
            2,010Unearned
                ESOP common stock
            
            
            **(42**
            **)**
            
            (50
            )Accumulated
                other comprehensive loss
            
            
            **(6**
            **)**
            
            (1
            )Retained
                earnings
            
            
            **1,511**
            
            
            1,431**Total
                common stock equity**
            
            
            **3,487**
            
            
            3,390**Preferred
                stock - not subject to mandatory redemption**
            
            
            **59**
            
            
            59**Long-term
                debt, net**
            
            
            **3,482**
            
            
            3,470**Total
                capitalization**
            
            
            **7,028**
            
            
            6,919**Current
                liabilities**Current
                portion of long-term debt
            
            
            **200**
            
            
            200Accounts
                payable
            
            
            **277**
            
            
            310Payables
                to affiliated companies
            
            
            **42**
            
            
            108Interest
                accrued
            
            
            **62**
            
            
            69Customer
                deposits
            
            
            **62**
            
            
            59Income
                taxes accrued
            
            
            **66**
            
            
            68Current
                portion of unearned revenue
            
            
            **56**
            
            
            71Other
                current liabilities
            
            
            **166**
            
            
            154**Total
                current liabilities**
            
            
            **931**
            
            
            1,039**Deferred
                credits and other liabilities**Noncurrent
                income tax liabilities
            
            
            **854**
            
            
            909Accumulated
                deferred investment tax credits
            
            
            **126**
            
            
            128Regulatory
                liabilities
            
            
            **1,337**
            
            
            1,320Asset
                retirement obligations
            
            
            **1,019**
            
            
            1,004Accrued
                pension and other benefits
            
            
            **587**
            
            
            581Other
                liabilities and deferred credits
            
            
            **111**
            
            
            120**Total
                deferred credits and other liabilities**
            
            
            **4,034**
            
            
            4,062**Commitments
                and contingencies (Notes 11 and 12)****Total
                capitalization and liabilities**
            
            **$**
            **11,993**
            
            $
            12,020





*See
      Notes to PEC Consolidated Interim Financial Statements.*


13


CAROLINA
      POWER & LIGHT COMPANY


d/b/a
      PROGRESS ENERGY CAROLINAS, INC.


**UNAUDITED
                CONSOLIDATED STATEMENTS of CASH FLOWS***(in
                millions)*Three
                Months Ended March 31
            
            **2007**
            
            2006**Operating****activities**Net
                income
            
            **$**
            **124**
            
            $
            86Adjustments
                to reconcile net income to net cash provided by operating
                activitiesDepreciation
                and amortization
            
            
            **138**
            
            
            147Deferred
                income taxes and investment tax credits, net
            
            
            **7**
            
            
            24Deferred
                fuel cost
            
            
            **44**
            
            
            24Other
                adjustments to net income
            
            
            **(11**
            **)**
            
            44Cash
                provided (used) by changes in operating assets and
                liabilitiesReceivables
            
            
            **25**
            
            
            79Receivables
                from affiliated companies
            
            
            **7**
            
            
            12Inventory
            
            
            **(8**
            **)**
            
            (15
            )Prepayments
                and other current assets
            
            
            **3**
            
            
            2Accounts
                payable
            
            
            **(17**
            **)**
            
            (6
            )Payables
                to affiliated companies
            
            
            **(66**
            **)**
            
            (13
            )Other
                current liabilities
            
            
            **(28**
            **)**
            
            (136
            )Other
                liabilities and deferred credits
            
            
            **-**
            
            
            (22
            )Other
                assets and deferred debits
            
            
            **(8**
            **)**
            
            11**Net
                cash provided by operating activities**
            
            
            **210**
            
            
            237**Investing****activities**Gross
                utility property additions
            
            
            **(208**
            **)**
            
            (151
            )Nuclear
                fuel additions
            
            
            **(38**
            **)**
            
            (46
            )Purchases
                of available-for-sale securities and other investments
            
            
            **(120**
            **)**
            
            (238
            )Proceeds
                from sales of available-for-sale securities and other
                investments
            
            
            **162**
            
            
            285Changes
                in advances to affiliates
            
            
            **24**
            
            
            -Other
                investing activities
            
            
            **6**
            
            
            -**Net
                cash used by investing activities**
            
            
            **(174**
            **)**
            
            (150
            )**Financing****activities**Net
                decrease in short-termdebt
            
            
            **-**
            
            
            (21
            )Changes
                in advances from affiliates
            
            
            **-**
            
            
            (1
            )Dividends
                paid to parent
            
            
            **(36**
            **)**
            
            (85
            )Dividends
                paid on preferred stock
            
            
            **(1**
            **)**
            
            (1
            )Other
                financing activities
            
            
            **11**
            
            
            1**Net
                cash used by financing activities**
            
            
            **(26**
            **)**
            
            (107
            )**Net****increase
                (decrease) in cash and cash equivalents**
            
            
            **10**
            
            
            (20
            )**Cash
                and****cash equivalents at beginning of
                period**
            
            
            **71**
            
            
            125**Cash
                and****cash equivalents at end of
                period**
            
            **$**
            **81**
            
            $
            105





*See
      Notes to PEC Consolidated Interim Financial Statements.*


14


**FLORIDA
      POWER CORPORATION**


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


**INTERIM
      FINANCIAL STATEMENTS**


**March
      31, 2007**





**UNAUDITED
                STATEMENTS of INCOME***(in
                millions)*Three
                Months Ended March 31
            
            **2007**
            
            2006**Operating
                revenues**
            
            **$**
            **1,011**
            
            $
            1,007**Operating
                expenses**Fuel
                used in electric generation
            
            
            **385**
            
            
            394Purchased
                power
            
            
            **163**
            
            
            165Operation
                and maintenance
            
            
            **175**
            
            
            166Depreciation
                and amortization
            
            
            **97**
            
            
            95Taxes
                other than on income
            
            
            **74**
            
            
            73Other
            
            
            **-**
            
            
            (3
            )**Total
                operating expenses**
            
            
            **894**
            
            
            890**Operating
                income**
            
            
            **117**
            
            
            117**Other
                income (expense)**Interest
                income
            
            
            **1**
            
            
            5Other,
                net
            
            
            **7**
            
            
            (1
            )**Total
                other income**
            
            
            **8**
            
            
            4**Interest
                charges**Interest
                charges
            
            
            **39**
            
            
            40Allowance
                for borrowed funds used during construction
            
            
            **(2**
            **)**
            
            (1
            )**Total
                interest charges, net**
            
            
            **37**
            
            
            39**Income
                before income tax**
            
            
            **88**
            
            
            82**Income
                tax expense**
            
            
            **27**
            
            
            29**Net
                income**
            
            
            **61**
            
            
            53**Preferred
                stock dividend requirement**
            
            
            **1**
            
            
            1**Earnings
                for common stock**
            
            **$**
            **60**
            
            $
            52





*See
      Notes to PEF Interim Financial Statements.*


15


FLORIDA
      POWER CORPORATION


d/b/a
      PROGRESS ENERGY FLORIDA, INC.


**UNAUDITED
                BALANCE SHEETS***(in
                millions)*
            
            **March
                31, 2007**
            
            December
                31, 2006**ASSETS****Utility
                plant**Utility
                plant in service
            
            **$**
            **9,258**
            
            $
            9,202Accumulated
                depreciation
            
            
            **(3,639**
            **)**
            
            (3,602
            )Utility
                plant in service, net
            
            
            **5,619**
            
            
            5,600Held
                for future use
            
            
            **7**
            
            
            7Construction
                work in progress
            
            
            **815**
            
            
            672Nuclear
                fuel, net of amortization
            
            
            **75**
            
            
            58**Total
                utility plant, net**
            
            
            **6,516**
            
            
            6,337**Current
                assets**Cash
                and cash equivalents
            
            
            **12**
            
            
            23Receivables,
                net
            
            
            **297**
            
            
            340Receivables
                from affiliated companies
            
            
            **9**
            
            
            11Deferred
                income taxes
            
            
            **27**
            
            
            86Inventory
            
            
            **460**
            
            
            436Deferred
                fuel cost
            
            
            **4**
            
            
            -Income
                taxes receivable
            
            
            **14**
            
            
            47Prepayments
                and other current assets
            
            
            **7**
            
            
            62**Total
                current assets**
            
            
            **830**
            
            
            1,005**Deferred
                debits and other assets**Regulatory
                assets
            
            
            **349**
            
            
            454Nuclear
                decommissioning trust funds
            
            
            **558**
            
            
            552Miscellaneous
                other property and investments
            
            
            **45**
            
            
            45Prepaid
                pension cost
            
            
            **180**
            
            
            174Derivative
                assets
            
            
            **17**
            
            
            2Other
                assets and deferred debits
            
            
            **28**
            
            
            24**Total
                deferred debits and other assets**
            
            
            **1,177**
            
            
            1,251**Total
                assets**
            
            **$**
            **8,523**
            
            $
            8,593**CAPITALIZATION
                AND LIABILITIES****Common
                stock equity**Common
                stock without par value, 60 million shares authorized, 100 shares
                issued
                and outstanding
            
            **$**
            **1,101**
            
            $
            1,100Accumulated
                other comprehensive loss
            
            
            **(1**
            **)**
            
            (1
            )Retained
                earnings
            
            
            **1,648**
            
            
            1,588**Total
                common stock equity**
            
            
            **2,748**
            
            
            2,687**Preferred
                stock - not subject to mandatory redemption**
            
            
            **34**
            
            
            34**Long-term
                debt, net**
            
            
            **2,389**
            
            
            2,468**Total
                capitalization**
            
            
            **5,171**
            
            
            5,189**Current
                liabilities**Current
                portion of long-term debt
            
            
            **169**
            
            
            89Notes
                payable to affiliated companies
            
            
            **11**
            
            
            47Accounts
                payable
            
            
            **274**
            
            
            292Payables
                to affiliated companies
            
            
            **45**
            
            
            116Customer
                deposits
            
            
            **174**
            
            
            168Interest
                accrued
            
            
            **32**
            
            
            38Derivative
                liabilities
            
            
            **33**
            
            
            89Current
                regulatory liabilities
            
            
            **143**
            
            
            76Other
                current liabilities
            
            
            **102**
            
            
            89**Total
                current liabilities**
            
            
            **983**
            
            
            1,004**Deferred
                credits and other liabilities**Noncurrent
                income tax liabilities
            
            
            **430**
            
            
            466Accumulated
                deferred investment tax credits
            
            
            **22**
            
            
            23Regulatory
                liabilities
            
            
            **1,117**
            
            
            1,091Asset
                retirement obligations
            
            
            **302**
            
            
            299Accrued
                pension and other benefits
            
            
            **332**
            
            
            332Other
                liabilities and deferred credits
            
            
            **166**
            
            
            189**Total
                deferred credits and other liabilities**
            
            
            **2,369**
            
            
            2,400**Commitments
                and contingencies (Notes 11 and 12)****Total
                capitalization and liabilities**
            
            **$**
            **8,523**
            
            $
            8,593





*See
      Notes to PEF Interim Financial Statements.*


16


FLORIDA
      POWER CORPORATION


d/b/a
      PROGRESS ENERGY FLORIDA, INC.


**UNAUDITED
                STATEMENTS of CASH FLOWS***(in
                millions)*Three
                Months Ended March 31
            
            **2007**
            
            2006**Operating
                activities**Net
                income
            
            **$**
            **61**
            
            $
            53Adjustments
                to reconcile net income to net cash provided by operating
                activitiesDepreciation
                and amortization
            
            
            **103**
            
            
            101Deferred
                income taxes and investment tax credits, net
            
            
            **14**
            
            
            19Deferred
                fuel cost
            
            
            **64**
            
            
            110Other
                adjustments to net income
            
            
            **-**
            
            
            10Cash
                provided (used) by changes in operating assets and
                liabilitiesReceivables
            
            
            **41**
            
            
            40Receivables
                from affiliated companies
            
            
            **2**
            
            
            4Inventory
            
            
            **(23**
            **)**
            
            (66
            )Prepayments
                and other current assets
            
            
            **56**
            
            
            4Accounts
                payable
            
            
            **18**
            
            
            (29
            )Payables
                to affiliated companies
            
            
            **(71**
            **)**
            
            (28
            )Other
                current liabilities
            
            
            **48**
            
            
            (19
            )Regulatory
                assets and liabilities
            
            
            **8**
            
            
            (2
            )Other
                liabilities and deferred credits
            
            
            **(9**
            **)**
            
            10Other
                assets and deferred debits
            
            
            **(3**
            **)**
            
            6**Net
                cash provided by operating activities**
            
            
            **309**
            
            
            213**Investing
                activities**Gross
                utility property additions
            
            
            **(261**
            **)**
            
            (162
            )Nuclear
                fuel additions
            
            
            **(23**
            **)**
            
            (6
            )Purchases
                of available-for-sale securities and other investments
            
            
            **(44**
            **)**
            
            (126
            )Proceeds
                from sales of available-for-sale securities and other
                investments
            
            
            **44**
            
            
            71Other
                investing activities
            
            
            **-**
            
            
            (3
            )**Net
                cash used by investing activities**
            
            
            **(284**
            **)**
            
            (226
            )**Financing
                activities**Changes
                in advances from affiliates
            
            
            **(36**
            **)**
            
            (13
            )Dividends
                paid to parent
            
            
            **-**
            
            
            (58
            )Dividends
                paid on preferred stock
            
            
            **(1**
            **)**
            
            (1
            )Other
                financing activities
            
            
            **1**
            
            
            -**Net
                cash used by financing activities**
            
            
            **(36**
            **)**
            
            (72
            )**Net
                decrease****in cash and cash equivalents**
            
            
            **(11**
            **)**
            
            (85
            )**Cash
                and cash equivalents at beginning of period**
            
            
            **23**
            
            
            218**Cash
                and cash equivalents at end of period**
            
            **$**
            **12**
            
            $
            133





*See
      Notes to PEF Interim Financial Statements.*


17


PROGRESS
      ENERGY, INC.


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


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


**COMBINED**  **NOTES
      TO UNAUDITED INTERIM FINANCIAL STATEMENTS**





**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 8, and 10 through 12PEF
            1,
                2, 4 through 8, and 10 through
                12


18


PROGRESS
      ENERGY, INC.


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


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


**COMBINED
      NOTES TO UNAUDITED 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 provisions 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. 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 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 seasonal fluctuations in energy sales and earnings from the
      Utilities. Income tax expense was increased (decreased) for the Progress
      Registrants for the three months ended March 31, 2007 and 2006, as
      follows:


19





Three
                Months Ended March 31,*(in
                millions)*
            
            **2007**
            
            2006Progress
                Energy
            
            **$**
            **(8**
            **)**
            $
            16PEC
            
            
            **(1**
            **)**
            
            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 March 31,*(in
                millions)*
            
            **2007**
            
            2006Progress
                Energy
            
            **$**
            **66**
            
            $
            65PEC
            
            
            **24**
            
            
            22PEF
            
            
            **42**
            
            
            43





The
      amounts included in these financial statements are unaudited but, in the opinion
      of management, reflect all normal recurring adjustments necessary to fairly
      present the Progress Registrants’ financial position and results of operations
      for the interim periods. 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 synthetic fuels production facility that qualifies for federal
      tax
      credits under Section 45K of the Code. Progress Energy, through its subsidiary
      Progress Fuels Corporation (Progress Fuels), is the primary beneficiary of,
      and
      continues to consolidate Ceredo. At March 31, 2007, the total assets of Ceredo
      were $37 million and were included in other current assets in the Consolidated
      Balance Sheets. See Note 3H 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
      March 31, 2007, the aggregate additional maximum loss exposure that we could
      be
      required to record in our income statement as a result of these arrangements
      was
      $7 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.




20


***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 March 31, 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 a 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 March 31, 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 $20
      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
      March 31, 2007, the aggregate maximum loss exposure that PEF could be required
      to record in its income statement as a result of these arrangements was $57
      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 STANDARDS**




In
      July
      2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in
      Income Taxes” (FIN 48). Enterprises must adopt FIN 48 through a cumulative
      effect adjustment to retained earnings at the beginning of their first fiscal
      year that begins after December 15, 2006, which for us was January 1, 2007.
      FIN
      48 applies to all tax positions within the scope of Statement of Financial
      Accounting Standards (SFAS) No. 109, “Accounting for Income Taxes,” and includes
      tax positions taken and tax positions expected to be taken. 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. FIN 48 also provides guidance
      on
      the related derecognition, classification, interest and penalties, accounting
      for interim periods, disclosure and transition of uncertain tax positions.
      See
      Note 6 for additional information regarding the adoption of FIN 48.




**3.** **DIVESTITURES**




**A.** **CCO
      - Georgia Operations**




On
      March
      9, 2007, our subsidiary, Progress Ventures, Inc. (PVI), entered into a series
      of
      transactions to sell substantially all of its Competitive Commercial Operations
      (CCO) physical and commercial assets and liabilities. Assets to be divested
      include approximately 1,900 megawatts (MW) of gas-fired generation assets in
      Georgia. The sale of the generation assets is expected to close in the summer
      of
      2007 for a net sales price of $603 million and is subject to federal regulatory
      approvals and customary closing conditions. We recorded an estimated loss of
      $226




21


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 noncash
      impairment recorded in 2006.




Additionally,
      PVI has agreed, subject to obtaining federal regulatory approvals, customer
      consents and customary closing conditions, to assign the CCO 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. As a result of the
      assignment, PVI will make a net cash payment of $347 million, which will
      represent the net cost to assign the Georgia Contracts and other related
      contracts. As of March 31, 2007, we estimated, as a result of the assignments,
      the charge associated with exit costs will be in excess of $320 million
      after-tax. The
      actual amount of the exit costs to be recorded may vary based on changes in
      commodity prices. However, any variation in the estimated exit costs will have
      an offsetting impact in net earnings from discontinued operations. The contract
      assignment agreement is expected to close in the summer of 2007.




We
      estimate pre-tax net proceeds on these transactions to be $256 million. Proceeds
      will be used 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 three months ended March
      31, 2007 and 2006 was $8 million and $10 million, respectively. We ceased
      recording depreciation upon classification of the assets as discontinued
      operations in December 2006. After-tax depreciation expense during the three
      months ended March 31, 2006 was $4 million. Results of discontinued operations
      for the three months ended March 31 were as follows:


*(in
                millions)*
            
            **2007**
            
            2006Revenues
            
            **$**
            **252**
            
            $
            188Earnings
                (loss) before income taxes
            
            
            **70**
            
            
            (95
            )Income
                tax (expense) benefit
            
            
            **(27**
            **)**
            
            35Net
                earnings (loss) from discontinued operations
            
            
            **43**
            
            
            (60
            )Reversal
                of estimated loss on disposal of discontinued operations, including
                income
                tax benefit of $2
            
            
            **16**
            
            
            -Earnings
                (loss) from discontinued operations
            
            **$**
            **59**
            
            $
            (60
            )





**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. Proceeds from the sale have been used
      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 months ended
      March 31, 2006, was $4 million. We ceased recording depreciation upon
      classification of the assets as discontinued operations in July 2006. After-tax
      depreciation expense during the three months ended March 31, 2006, was $8
      million. Results of discontinued operations for the three months ended March
      31
      were as follows:


22





*(in
                millions)*
            
            **2007**
            
            2006Revenues
            
            **$**
            **-**
            
            $
            31Earnings
                before income taxes
            
            
            **-**
            
            
            39Income
                tax expense
            
            
            **-**
            
            
            (18
            )Net
                earnings from discontinued operations
            
            
            **-**
            
            
            21Loss
                on disposal of discontinued operations, including income tax benefit
                of
                $1
            
            
            **(1**
            **)**
            
            -(Loss)
                earnings from discontinued operations
            
            **$**
            **(1**
            **)**
            $
            21





**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 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 $67 million during
      the
      year ended December 31, 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 three months ended
      March 31, 2006 was $4 million. We ceased recording depreciation upon
      classification of the assets as discontinued operations in May 2006. After-tax
      depreciation expense during the three months ended March 31, 2006 was $2
      million. Results of discontinued operations for the three months ended March
      31
      were as follows:


*(in
                millions)*
            
            2006Revenues
            
            $
            6Loss
                before income taxes
            
            
            (5
            )Income
                tax benefit
            
            
            2Loss
                from discontinued operations
            
            $
            (3
            )





**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 10 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 remainder of 2006, we recorded
      an additional after-tax gain of $4 million after finalizing the working capital
      adjustment and other operating estimates.




The
      accompanying consolidated financial statements have been restated for all
      periods presented to reflect the operations of PT LLC 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




23


expense
      allocated was less than $1 million for the three months ended March 31, 2006.
      We
      ceased recording depreciation
      upon classification of the assets as discontinued operations in January 2006.
      After-tax depreciation expense during the three months ended March 31, 2006,
      was
      $1 million. Results of discontinued operations for the three months ended March
      31 were as follows:


*(in
                millions)*
            
            2006Revenues
            
            $
            18Earnings
                before income taxes and minority interest
            
            
            1Income
                tax expense
            
            
            (4
            )Minority
                interest
            
            
            (3
            )Net
                loss from discontinued operations
            
            
            (6
            )Gain
                on disposal of discontinued operations, including income tax expense
                of
                $13 and minority interest of $36
            
            
            24Earnings
                from discontinued operations
            
            $
            18





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 12A. 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 operating under long-term contracts
      with PEF. 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 other fuels business is Progress
      Materials, Inc. and is expected to be sold in 2007.




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 each of the three months ended March 31, 2007
      and
      2006. We ceased recording depreciation upon classification of the assets as
      discontinued operations. After-tax depreciation expense during the three months
      ended March 31, 2006 was less than $1 million. Results of discontinued
      operations for the three months ended March 31 were as follows:


*(in
                millions)*
            
            **2007**
            
            2006Revenues
            
            **$**
            **2**
            
            $
            8Earnings
                before income taxes
            
            
            **1**
            
            
            3Income
                tax expense
            
            
            **-**
            
            
            (1
            )Net
                earnings from discontinued operations
            
            
            **1**
            
            
            2Gain
                on disposal of discontinued operations, including income tax expense
                of
                $1
            
            
            **-**
            
            
            2Earnings
                from discontinued operations
            
            **$**
            **1**
            
            $
            4





**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. 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 three months ended March
      31,
      2006, we recorded an after-tax loss of $15 million on the sale of these assets.
      During the remainder of 2006, we recorded an after-tax gain of $5 million after
      finalizing the working capital adjustment and other operating estimates. The
      remaining coal mining operations are expected to be sold in 2007.




The
      accompanying consolidated financial statements have been restated for all
      periods presented to reflect the coal mining operations as discontinued
      operations. Interest expense has been allocated to discontinued operations
      based




24


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 three months ended March
      31, 2006, was $1 million. There was less than $1 million allocated for the
      three
      months ended March 31, 2007. We ceased recording depreciation expense upon
      classification of the coal mining operations as discontinued operations in
      November 2005. Results of discontinued operations for the three months ended
      March 31 were as follows:


*(in
                millions)*
            
            **2007**
            
            2006Revenues
            
            **$**
            **7**
            
            $
            35Loss
                before income taxes
            
            
            **(6**
            **)**
            
            (7
            )Income
                tax benefit
            
            
            **2**
            
            
            2Net
                loss from discontinued operations
            
            
            **(4**
            **)**
            
            (5
            )Loss
                on disposal of discontinued operations, including income tax benefit
                of
                $9
            
            
            **-**
            
            
            (15
            )Loss
                from discontinued operations
            
            **$**
            **(4**
            **)**
            $
            (20
            )





**G****.** **Net
      Assets of Discontinued Operations**




At
      March
      31, 2007, and December 31, 2006, the assets and liabilities of CCO, the
      remaining coal mining operations 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:


*(in
                millions)*
            
            **March
                31, 2007**
            
            December
                31, 2006Accounts
                receivable
            
            **$**
            **1**
            
            $
            45Inventory
            
            
            **22**
            
            
            24Other
                current assets
            
            
            **13**
            
            
            28Total
                property, plant and equipment, net
            
            
            **586**
            
            
            573Total
                other assets
            
            
            **273**
            
            
            217Assets
                of discontinued operations
            
            **$**
            **895**
            
            $
            887Accounts
                payable
            
            **$**
            **1**
            
            $
            43Accrued
                expenses
            
            
            **166**
            
            
            122Long-term
                liabilities
            
            
            **12**
            
            
            24Liabilities
                of discontinued operations
            
            **$**
            **17****9**
            
            $
            189





**H****.** **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 qualifying synthetic fuels,
      to an
      unrelated 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 will be received as we produce and sell qualified synthetic
      fuels on behalf of the buyer during 2007. Actual proceeds could differ based
      on
      actual production levels, which shall be determined by the buyer. The estimated
      production level of Ceredo is 2.8 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 March 31, 2007 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 from the disposal will be recognized
      over time as we produce and sell qualified synthetic fuels for the buyer. The
      reconfirmation private letter ruling request has been submitted to the
      IRS.




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. Ceredo’s long-lived assets were fully
      impaired during the second quarter of 2006. Subsequent to the disposal, we
      remain the primary beneficiary of Ceredo and will continue to consolidate Ceredo
      in accordance with FIN 46R, but we anticipate




25


recording
      a 100 percent minority interest. Consequently, we anticipate that there will
      be
      no net earnings impact. 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 the deferred gain. The ultimate
      resolution of these matters could result in adjustments to the gain on disposal
      in future periods. See general discussion of guarantees at Note
      12A.




**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 oxide (NOx) and sulfur dioxide (SO 2 )
      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 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 months ended March 31, 2007, and 2006, PEC recognized amortization of
      $8
      million and $22 million, respectively, and has recognized $543 million in
      cumulative amortization through March 31, 2007. We will record at least the
      remaining amortization requirement of $26 million during the nine-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. We cannot predict the
      outcome of this matter.




See
      Note
      11B 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 customers. PEC is asking the SCPSC to approve a $12 million
      increase in rates. PEC requested the increase for underrecovered fuel costs
      associated with prior year settlements and to meet future expected fuel costs.
      If approved, the increase would take effect July 1, 2007 and would increase
      residential electric bills by $1.76 per 1,000 kWhs, or 1.9 percent, for fuel
      cost recovery. A
      hearing
      on the matter has been scheduled by the SCPSC for June 13, 2007. We cannot
      predict the outcome of this matter.




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 the Carolinas
      Industrial Group for Fair Utility Rates II. The settlement agreement provided
      for a $177 million, or 6.7 percent increase in rates effective October 1, 2006.
      The settlement agreement further provides for rate increases of $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% on the difference between its
      fuel factor proposed in its original request to the NCUC and the settlement
      agreement’s factor. Effective October 1, 2006, residential electric bills




26


increased
      by $4.87 per 1,000 kWhs for fuel cost recovery.




On
      November 21, 2006, the Carolina Utility Customers Association (CUCA) filed
      an
      appeal with the North Carolina Tenth District Court of Appeals of the NCUC’s
      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. We cannot predict the outcome of this
      matter.




**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 11A). 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 first quarter of 2007, PEC recorded $1 million of
      amortization expense. Additionally, PEC reduced the regulatory asset and
      corresponding liability by $4 million during the first quarter of 2007 based
      on
      newly available data regarding certain remediation sites (See Note
      11A).




**B.** **PEF
      Retail Rate Matters**




**PASS-THROUGH
      CLAUSE COST RECOVERY**




On
      August
      10, 2006, Florida’s Office of Public Counsel (OPC) filed a petition with the
      FPSC asking that the FPSC require PEF to refund to ratepayers $143 million,
      plus
      interest, of alleged excessive past fuel recovery charges and SO 2 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. The OPC claims that although 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 August 30, 2006, PEF filed
      a
      motion with the FPSC to dismiss the petition on the grounds that the OPC
      petition would require the FPSC to engage in retroactive ratemaking for rates
      previously approved under the fuel recovery clause. On September 13, 2006,
      the
      OPC filed a memorandum in opposition to PEF’s motion to dismiss the petition.
      PEF’s motion to dismiss was denied by the FPSC on December 19, 2006. The FPSC
      held a hearing on the matter from April 2 through April 5, 2007. We anticipate
      that the FPSC will reach a decision on this matter later in 2007. PEF believes
      that its coal procurement practices were prudent and that it has sound legal
      and
      factual arguments to successfully defend its position. 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 costs through PEF’s fuel recovery clause. 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 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
      of
      uprate costs 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
      uprate costs should be recovered through the fuel recovery clause. On May 4,
      2007, PEF filed amended testimony clarifying the scope of the project. The
      FPSC
      has scheduled an August 7, 2007, hearing on this matter. If PEF does not receive
      approval to recover the uprate costs through the fuel recovery clause, these
      costs will be recoverable through base rates, similar to other utility plant




27


additions.
      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 current estimate of
      in-service cost of $327 million, which will result in a base rate increase
      of
      $52 million, as provided for by PEF’s base rate agreement. The rate base
      increase would become effective upon Hines Unit 4 being placed in service,
      which
      PEF anticipates will be on December 1, 2007. We cannot predict the outcome
      of
      this matter.




**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 March 31,*(in
                millions)*
            **2007**
            2006Weighted-average
                common shares - basic
            **254**
            249Net
                effect of dilutive stock-based compensation plans
            **1**
            -Weighted-average
                shares - fully dilutive
            **255**
            249





**B.** **Comprehensive
      Income**




***Progress
      Energy***


Three
                Months Ended March 31,*(in
                millions)*
            
            **2007**
            
            2006Net
                income
            
            **$**
            **275**
            
            $
            45Other
                comprehensive (loss) incomeReclassification
                adjustments included in net incomeChange
                in cash flow hedges (net of tax benefit of $2)
            
            
            **-**
            
            
            (4
            )Change
                in unrecognized items for pension and other postretirement benefits
                (net
                of tax expense of $-)
            
            
            **1**
            
            
            -Changes
                in net unrealized gains on cash flow hedges (net of tax expense of
                $7)
            
            
            **-**
            
            
            13Other
                (net of tax (benefit) expense of $(3) and $2,
                respectively)
            
            
            **(2**
            **)**
            
            5Other
                comprehensive (loss) income
            
            
            **(1**
            **)**
            
            14Comprehensive
                income
            
            **$**
            **274**
            
            $
            59





28


***PEC***


Three
                Months Ended March 31,*(in
                millions)*
            
            **2007**
            
            2006Net
                income
            
            **$**
            **124**
            
            $
            86Other
                comprehensive (loss) incomeChanges
                in net unrealized losses on cash flow hedges (net of tax benefit
                of
                $1)
            
            
            **(1**
            **)**
            
            -Other
                (net of tax benefit of $1 and $-,
                respectively)
            
            
            **(4**
            **)**
            
            1Other
                comprehensive (loss) income
            
            
            **(5**
            **)**
            
            1Comprehensive
                income
            
            **$**
            **119**
            
            $
            87





***PEF***





Comprehensive
      income and net income for PEF for the three months ended March 31, 2007 and
      2006
      were $61 million and $53 million, respectively.




**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. For the three
      months ended March 31, 2007 and 2006, respectively, we issued approximately
      1.5
      million shares and 0.7 million shares of common stock resulting in approximately
      $65 million and $28 million in proceeds. Included in these amounts were
      approximately 0.2 million shares and 0.3 million shares for proceeds of
      approximately $11 million and $14 million, respectively, to meet the
      requirements of the Progress Energy 401(k) Savings and Stock Ownership Plan
      (401(k)) and the Investor Plus Stock Purchase Plan. 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 401(k) and the Investor Plus Stock
      Purchase Plan with original issue shares.




**6.**  **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 reduction of the January 1, 2007,
      balance of retained earnings of $2 million and an increase in regulatory assets
      of $4 million. 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 affect
      the effective tax rate for income from continuing operations, if
      recognized.




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 1998 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
      through 2005. We cannot predict when those examinations will be completed.
      Due
      to the expected closure of certain tax years and positions, we believe it is
      reasonably possible that we would recognize a decrease in the total amounts
      of
      unrecognized tax benefits ranging from $35 million to $45 million during the
      twelve-month period ending March 31, 2008.




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




***PEC***




PEC
      adopted the provisions of FIN 48 on January 1, 2007, which was accounted for
      as
      a reduction of the January 1,




29


2007,
      balance of retained earnings of $6 million. 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 affect the effective tax rate, if
      recognized.




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 1998 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 through 2005. PEC cannot
      predict when those examinations will be completed. Due to the expected closure
      of certain tax years and positions, PEC believes it is reasonably possible
      that
      it would recognize a decrease in the total amounts of unrecognized tax benefits
      ranging from $10 million to $15 million during the twelve-month period ending
      March 31, 2008.




PEC
      recognizes accrued interest related to unrecognized tax benefits in interest
      charges and penalties in other, net on the Consolidated Statements of Income.
      As
      of January 1, 2007, PEC had accrued $4 million for interest and
      penalties.




***PEF***




PEF
      adopted the provisions of FIN 48 on January 1, 2007, which was accounted for
      as
      a reduction of the January 1, 2007, balance of retained earnings of $1 million
      and an increase in regulatory assets of $4 million. 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 affect the effective tax rate, if
      recognized.




We
      file
      consolidated federal and state income tax returns that include PEF. PEF’s open
      federal tax years are from 1999 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 through 2005. PEF cannot predict when those examinations
      will be completed. Due to the expected closure of certain tax years and
      positions, PEF believes it is reasonably possible that it would recognize a
      decrease in the total amounts of unrecognized tax benefits ranging from $10
      million to $15 million during the twelve-month period ending March 31,
      2008.




PEF
      recognizes accrued interest related to unrecognized tax benefits in interest
      charges and penalties in other, net on the Statements of Income. As of January
      1, 2007, PEF had accrued $7 million for interest and penalties.




**7.**  **BENEFIT
      PLANS**




We
      have
      noncontributory defined benefit retirement plans for substantially all full-time
      employees that provide pension benefits. We also have supplementary defined
      benefit pension plans that provide benefits to higher-level employees. In
      addition to pension benefits, we provide contributory other postretirement
      benefits (OPEB), including certain health care and life insurance benefits,
      for
      retired employees who meet specified criteria. The components of the net
      periodic benefit cost for the respective Progress Registrants for the three
      months ended March 31 were:




***Progress
      Energy***


Pension
                Benefits
            
            Other
                Postretirement Benefits*(in
                millions)*
            
            **2007**
            
            2006
            
            **2007**
            
            2006Service
                cost
            
            **$**
            **11**
            
            $
            12
            
            **$**
            **2**
            
            $
            2Interest
                cost
            
            
            **30**
            
            
            29
            
            
            **9**
            
            
            9Expected
                return on plan assets
            
            
            **(39**
            **)**
            
            (36
            )
            
            **(1**
            **)**
            
            (1
            )Amortization
                of actuarial loss (a)
            
            
            **4**
            
            
            6
            
            
            **1**
            
            
            2Other
                amortization, net (a)
            
            
            **-**
            
            
            -
            
            
            **1**
            
            
            1Net
                periodic cost
            
            **$**
            **6**
            
            $
            11
            
            **$**
            **12**
            
            $
            13





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




30


**PEC**


Pension
                Benefits
            
            Other
                Postretirement Benefits*(in
                millions)*
            
            **2007**
            
            2006
            
            **2007**
            
            2006Service
                cost
            
            **$**
            **5**
            
            $
            6
            
            **$**
            **1**
            
            $
            1Interest
                cost
            
            
            **14**
            
            
            13
            
            
            **5**
            
            
            5Expected
                return on plan assets
            
            
            **(15**
            **)**
            
            (15
            )
            
            **(1**
            **)**
            
            (1
            )Amortization
                of actuarial loss
            
            
            **3**
            
            
            3
            
            
            **1**
            
            
            1Net
                periodic cost
            
            **$**
            **7**
            
            $
            7
            
            **$**
            **6**
            
            $
            6





***PEF***


Pension
                Benefits
            
            Other
                Postretirement Benefits*(in
                millions)*
            
            **2007**
            
            2006
            
            **2007**
            
            2006Service
                cost
            
            **$**
            **4**
            
            $
            4
            
            **$**
            **1**
            
            $
            1Interest
                cost
            
            
            **13**
            
            
            12
            
            
            **3**
            
            
            3Expected
                return on plan assets
            
            
            **(21**
            **)**
            
            (19
            )
            
            **-**
            
            
            -Amortization
                of actuarial loss
            
            
            **-**
            
            
            2
            
            
            **-**
            
            
            -Other
                amortization, net
            
            
            **-**
            
            
            -
            
            
            **1**
            
            
            1Net
                periodic (benefit) cost
            
            **$**
            **(4**
            **)**
            $
            (1
            )
            **$**
            **5**
            
            $
            5





**8.**  **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 3, on March 9, 2007, we entered into two separate agreements
      to dispose of substantially all of PVI’s remaining CCO physical and commercial
      assets, and on October 2, 2006, we sold Gas. Due to these divestiture plans,
      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
      March
      31, 2007 and December 31, 2006, derivative assets of $178 million and $107
      million, respectively, were included in assets of discontinued operations and
      derivative liabilities of $10 million and $31 million, respectively, were
      included in liabilities of discontinued operations on the Consolidated Balance
      Sheets. For the three months ending March 31, 2007, gains from derivative
      instruments of $59 million were included in discontinued operations, net of
      tax
      on the Consolidated Statement of Income. For the three months ending March
      31,
      2006, net gains and losses from derivative instruments of discontinued
      operations were not material. For the three months ending March 31, 2007 and
      2006, there were no reclassifications to earnings due to discontinuance of
      the
      related cash flow hedges.




**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




31


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 10). At March 31,
      2007
      and December 31, 2006, the remaining liability was $13 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.




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. PEC and PEF did not have material
      outstanding positions in such contracts at March 31, 2007 and December 31,
      2006,
      other than those receiving regulatory accounting treatment, as discussed
      below.




At
      March
      31, 2007, the fair value of PEC’s derivative instruments was recorded as a $4
      million long-term derivative asset position included in other assets and
      deferred debits on the Consolidated Balance Sheet. At December 31, 2006, PEC
      did
      not have material outstanding positions in such contracts.




At
      March
      31, 2007, the fair value of PEF’s derivative instruments was recorded as a $2
      million short-term derivative asset position included in other assets and
      deferred debits, a $17 million long-term derivative asset position included
      in
      derivative assets, a $31 million short-term derivative liability position
      included in derivative liabilities, and an $11 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
      derivative assets, 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.




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 3H,
      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. At March 31, 2007, the fair value of these contracts was recorded as
      a
      $110 million short-term derivative asset position, including $37 million at
      Ceredo. The fair value of these contracts was included in derivative assets
      on
      the Consolidated Balance Sheet. During the three months ended March 31, 2007,
      we
      recorded net pre-tax gains of $45 million in diversified business revenues
      related to these contracts. We anticipate that future mark-to-market changes
      on
      the Ceredo portion of the derivatives contracts will have no net earnings
      impact.




**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 March 31, 2007, we and the Utilities did not have




32


material
      outstanding positions in such contracts. The ineffective portion of commodity
      cash flow hedges for the three months ended March 31, 2007 and 2006, was not
      material to our or the Utilities’ results of operations.




The
      fair
      values of our commodity cash flow hedges at December 31, 2006, were as
      follows:


December
                31, 2006*(in
                millions)*
            
            Progress
                Energy
            
            PEC
            
            PEFFair
                value of assets
            
            $
            2
            
            $
            2
            
            $
            -Fair
                value of liabilities
            
            
            -
            
            
            -
            
            
            -Fair
                value, net
            
            $
            2
            
            $
            2
            
            $
            -





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




At
      March
      31, 2007 and December 31, 2006, the amount recorded in our, PEC’s or PEF’s
      accumulated other comprehensive income (AOCI) related to commodity cash flow
      hedges was not material.




**B.** **Interest
      Rate Derivatives - Fair Value or Cash Flow Hedges**




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




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


**March
                31, 2007**
            
            December
                31, 2006*(in
                millions)*
            
            **Progress
                Energy**
            
            **PEC**
            
            **PEF**
            
            Progress
                Energy
            
            PEC
            
            PEFInterest
                rate cash flow hedges
            
            **$**
            **(4**
            **)**
            **$**
            **(2**
            **)**
            **$**
            **(2**
            **)**
            $
            (2
            )
            $
            (1
            )
            $
            (1
            )Interest
                rate fair value hedges
            
            
            **(1**
            **)**
            
            **-**
            
            
            **-**
            
            
            (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 months ended March 31, 2007 and 2006, was not material
      to
      our or the Utilities’ results of operations.




The
      following table presents selected information related to our interest rate
      cash
      flow hedges at March 31, 2007:


*(term
                in years/millions of dollars)*
            
            **Progress
                Energy**
            
            **PEC**
            
            **PEF**Maximum
                term
            
            Less
                than 1
            
            Less
                than 1
            
            Less
                than 1Accumulated
                other comprehensive loss, net of tax(a)
            
            $
            (13
            )
            $
            (6
            )
            $
            (1
            )Portion
                expected to be reclassified to earnings during the next
              12
                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.





PEF
      entered into a $50 million forward starting swap on February 16, 2007, to
      mitigate exposure to interest rate risk




33


in
      anticipation of future debt issuances.




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.




At
      March
      31, 2007, we had $150 million notional of interest rate cash flow hedges,
      including $50 million notional at PEC and $100 million notional at PEF. 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.





**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 March 31, 2007 and December 31, 2006,
      we
      had $50 million notional of interest rate fair value hedges. At March 31, 2007
      and December 31, 2006, the Utilities had no open interest rate fair value
      hedges.




**9.**  **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.




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.




34


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 months ended March 31:


IncomeRevenues
            
            (Loss)
                from*(in
                millions)*
            
            Unaffiliated
            
            Intersegment
            
            Total
            
            Continuing
              Operations
            
            Assets**2007****PEC**
            
            **$**
            **1,058**
            
            **$**
            **-**
            
            **$**
            **1,058**
            
            **$**
            **123**
            
            **$**
            **11,993****PEF**
            
            
            **1,011**
            
            
            **-**
            
            
            **1,011**
            
            
            **60**
            
            
            **8,523****Coal
                and Synthetic Fuels**
            
            
            **263**
            
            
            **2**
            
            
            **265**
            
            
            **57**
            
            
            **372****Corporate
                and Other**
            
            
            **2**
            
            
            **85**
            
            
            **87**
            
            
            **(20**
            **)**
            
            **15,658****Eliminations**
            
            
            **-**
            
            
            **(87**
            **)**
            
            **(87**
            **)**
            
            -
            
            
            **(11,722**
            **)****Totals**
            
            **$**
            **2,334**
            
            **$**
            **-**
            
            **$**
            **2,334**
            
            **$**
            **220**
            
            **$**
            **24,824**2006PEC
            
            $
            978
            
            $
            -
            
            $
            978
            
            $
            85PEF
            
            
            1,007
            
            
            -
            
            
            1,007
            
            
            52Coal
                and Synthetic Fuels
            
            
            238
            
            
            78
            
            
            316
            
            
            9Corporate
                and Other
            
            
            -
            
            
            89
            
            
            89
            
            
            (61
            )Eliminations
            
            
            -
            
            
            (167
            )
            
            (167
            )
            
            -Totals
            
            $
            2,223
            
            $
            -
            
            $
            2,223
            
            $
            85





35





**10.**  **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 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 March 31,*(in
                millions)*
            
            **2007**
            
            2006Other
                incomeNonregulated
                energy and delivery services income
            
            **$**
            **9**
            
            $
            8DIG
                Issue C20 amortization (see Note 8)
            
            
            **−**
            
            
            1CVOs
                unrealized gain
            
            
            **1**
            
            
            −Gain
                on sale of Level 3 stock (a)
            
            
            **−**
            
            
            25Investment
                gains
            
            
            **1**
            
            
            2Income
                from equity investments
            
            
            **2**
            
            
            −AFUDC
                equity
            
            
            **9**
            
            
            3Other
            
            
            **4**
            
            
            5Total
                other income
            
            
            **26**
            
            
            44Other
                expenseNonregulated
                energy and delivery services expenses
            
            
            **7**
            
            
            6Donations
            
            
            **4**
            
            
            7Loss
                from equity investments
            
            
            **4**
            
            
            1CVOs
                unrealized loss
            
            
            **−**
            
            
            25Other
            
            
            **2**
            
            
            7Total
                other expense
            
            
            **17**
            
            
            46Other,
                net - Progress Energy
            
            **$**
            **9**
            
            $
            (2
            )





(a)
            Other
                income includes a $25 million gain from the sale of approximately
                15
                million shares of Level 3 stock received as part of the sale of our
                interest in PT LLC (See Note 3D). This gain is prior to the consideration
                of minority interest.





36


***PEC***


Three
                Months Ended March 31,*(in
                millions)*
            
            **2007**
            
            2006Other
                incomeNonregulated
                energy and delivery services income
            
            **$**
            **2**
            
            $
            2DIG
                Issue C20 amortization (see Note 8)
            
            
            **−**
            
            
            1Income
                from equity investments
            
            
            **2**
            
            
            −AFUDC
                equity
            
            
            **2**
            
            
            1Other
            
            
            **4**
            
            
            3Total
                other income
            
            
            **10**
            
            
            7Other
                expenseNonregulated
                energy and delivery services expenses
            
            
            **2**
            
            
            1Donations
            
            
            **2**
            
            
            3Loss
                from equity investments
            
            
            **1**
            
            
            −Other
            
            
            **2**
            
            
            4Total
                other expense
            
            
            **7**
            
            
            8Other,
                net - PEC
            
            **$**
            **3**
            
            $
            (1
            )





***PEF***


Three
                Months Ended March 31,*(in
                millions)*
            
            **2007**
            
            2006Other
                incomeNonregulated
                energy and delivery services income
            
            **$**
            **7**
            
            
            6Investment
                gains
            
            
            **−**
            
            
            1AFUDC
                equity
            
            
            **7**
            
            
            2Total
                other income
            
            
            **14**
            
            
            9Other
                expenseNonregulated
                energy and delivery services expenses
            
            
            **5**
            
            
            5Donations
            
            
            **2**
            
            
            3Other
            
            
            **−**
            
            
            2Total
                other expense
            
            
            **7**
            
            
            10Other,
                net - PEF
            
            **$**
            **7**
            
            $
            (1
            )





**11.**  **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




37


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)*
            
            **March
                31, 2007**
            
            December
                31, 2006PECMGP
                and other sites(a)
            
            **$**
            **16**
            
            $
            22PEFRemediation
                of distribution and substation transformers
            
            
            **40**
            
            
            43MGP
                and other sites
            
            
            **18**
            
            
            18Total
                PEF environmental remediation accruals(b)
            
            
            **58**
            
            
            61Progress
                Energy nonregulated operations
            
            
            **3**
            
            
            3Total
                Progress Energy environmental remediation accruals
            
            **$**
            **77**
            
            $
            86





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


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





***Progress
      Energy***




In
      addition to the Utilities’ sites, discussed under “PEC” and “PEF” below, 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. At March 31, 2007 and December 31,
      2006, the remaining accrual balance was approximately $3 million. Expenditures
      related to this liability were not material for the three months ended March
      31,
      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 12A).




***PEC***




For
      the
      three months ended March 31, 2007, including the Ward Transformer site and
      MGP
      sites discussed below, PEC reduced its accrual by approximately $5 million,
      primarily related to the Ward Transformer site, and spent approximately $1
      million. For the three months ended March 31, 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
      $3 million. In October 2006, PEC received orders from the NCUC and SCPSC to
      defer and amortize certain environmental remediation expenses (See Note
      4A).




PEC
      has
      recorded a minimum estimated total remediation cost for all of its remaining
      MGP
      sites based upon its




38


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




In
      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 $32 million. In May 2006, a meeting was called by the EPA to
      discuss a settlement proposal among the PRPs. An agreement among PRPs has not
      been reached; consequently, it is not possible at this time to reasonably
      estimate the amount of PEC’s share of the reimbursement for remediation of the
      Carolina Transformer site. The outcome of this matter cannot be
      predicted.




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 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 March 31, 2007, PEC’s recorded liability for the site was
      approximately $4 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.




***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 months ended March 31, 2007 and 2006,
      PEF accrued approximately $2 million and $38 million, respectively, due to
      additional sites expected to require remediation and spent approximately $5
      million and $1 million, respectively, related to the remediation of
      transformers. At March 31, 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 months ended March 31, 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 March 31, 2007, cumulative capital expenditures to date to comply with these
      environmental laws and regulations were $1.067 billion, including $1.009 billion
      at PEC and $58 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 SO 2 from
      their North Carolina coal-fired power plants in phases by 2013. Two of PEC’s
      largest coal-fired generation plants (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




39


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 SO 2 removal
      from its larger coal-fired units, including Roxboro No. 4 and Mayo, so as to
      avoid the installation of expensive emission controls on its smaller coal-fired
      units. In order to address the joint owner's concerns that such a compliance
      strategy would result in a disproportionate share of the cost of compliance
      on
      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 March 31, 2007 and December 31, 2006, the amount of the
      liability was $31 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 customers
      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 customers, 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 has, accordingly,
      recorded the indemnification expense to Clean Smokestacks Act
      amortization.




**12.**  **COMMITMENTS
      AND CONTINGENCIES**




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




**A.**  **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.” Such
      agreements include guarantees, standby letters of credit and surety bonds.
      At
      March 31, 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
      March
      31, 2007, we have issued guarantees and indemnifications of certain asset
      performance, legal, tax and environmental matters to third parties, including
      indemnifications made in connection with sales of businesses, and for timely
      payment of obligations in support of our nonwholly owned synthetic fuels
      operations. 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 matters for which we receive timely notice, our
      indemnity obligations may extend beyond the notice period. Certain
      indemnifications have no limitations as to time or maximum potential future
      payments. In 2005, PEC entered into an agreement with the joint owner of certain
      facilities at the Mayo and Roxboro plants to limit their aggregate costs
      associated with capital expenditures to comply with the Clean Smokestacks Act
      and recognized a liability related to this indemnification (See Note 11B).
      PEC’s
      maximum exposure cannot be determined. At March 31, 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 March 31, 2007
      and December 31, 2006, we have recorded liabilities related to guarantees and
      indemnifications to third parties of approximately $82 million and $60 million,
      respectively. These amounts include $31 million and $29 million, respectively,
      for PEC and $8 million for PEF at March 31, 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 of certain payments
      of two wholly owned indirect subsidiaries. See Note 13 for additional
      information.




40


**B.** **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’s scheduling order,
      issued on March 23, 2006, included an anticipated trial date in late
      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. Circuit Court) 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. Circuit Court rejected
      the challenge to the constitutionality of the resolution approving Yucca
      Mountain, but ruled that the EPA was wrong to set a 10,000-year compliance
      period in the radiation protection standard. In August 2005, the EPA issued
      new
      proposed standards. The proposed standards include a 1,000,000-year compliance
      period in the radiation protection standard. Comments were due November 21,
      2005, and are being reviewed by the EPA. The 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. The DOE has requested $495 million for fiscal year 2008.
      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.




41


**SYNTHETIC
      FUEL****S 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.




**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.




**13.**  **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 11B in the
      2006
      Form 10-K, there were no restrictions on PEC’s or PEF’s retained
      earnings.




42


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, Gas,
      DeSoto, Rowan, Dixie Fuels and other fuels business as discontinued operations
      as described in Note 3.




43




Condensed
                Consolidating Statement of Income
              Three
                Months Ended March 31, 2007*(in
                millions)*
            
            **Parent**
            
            **Subsidiary
                Guarantor**
            
            **Other**
            
            **Progress
                Energy, Inc.****Operating
                revenues**Electric
            
            $
            **−**
            
            $
            1,011
            
            $
            1,057
            
            $
            2,068Diversified
                business
            
            
            **−**
            
            
            236
            
            
            30
            
            
            266**Total
                operating revenues**
            
            
            **−**
            
            
            1,247
            
            
            1,087
            
            
            2,334**Operating
                expenses**UtilityFuel
                used in electric generation
            
            
            **−**
            
            
            385
            
            
            351
            
            
            736Purchased
                power
            
            
            **−**
            
            
            163
            
            
            58
            
            
            221Operation
                and maintenance
            
            
            5
            
            
            175
            
            
            240
            
            
            420Depreciation
                and amortization
            
            
            **−**
            
            
            97
            
            
            122
            
            
            219Taxes
                other than on income
            
            
            **−**
            
            
            74
            
            
            50
            
            
            124Other
            
            
            **−**
            
            
            **−**
            
            
            (1
            )
            
            (1
            )Diversified
                businessCost
                of sales
            
            
            **−**
            
            
            224
            
            
            20
            
            
            244Depreciation
                and amortization
            
            
            **−**
            
            
            2
            
            
            **−**
            
            
            2Gain
                on the sale of assets
            
            
            **−**
            
            
            (16
            )
            
            **−**
            
            
            (16
            )Other
            
            
            **−**
            
            
            15
            
            
            3
            
            
            18**Total
                operating expenses**
            
            
            5
            
            
            1,119
            
            
            843
            
            
            1,967**Operating
                (loss) income**
            
            
            (5
            )
            
            128
            
            
            244
            
            
            367Other
                income, net
            
            
            6
            
            
            6
            
            
            5
            
            
            17Interest
                charges, net
            
            
            47
            
            
            45
            
            
            49
            
            
            141**(Loss)
                income from continuing operations before income tax, equity in earnings
                of
                consolidated subsidiaries and minority interest**
            
            
            (46
            )
            
            89
            
            
            200
            
            
            243**Income
                tax (benefit) expense**
            
            
            (19
            )
            
            (1
            )
            
            39
            
            
            19**Equity
                in earnings of consolidated subsidiaries**
            
            
            302
            
            
            **−**
            
            
            (302
            )
            
            **−****Minority
                interest in subsidiaries’ income, net of tax**
            
            
            **−**
            
            
            4
            
            
            **−**
            
            
            4**Income
                (loss) from continuing operations**
            
            
            275
            
            
            86
            
            
            (141
            )
            
            220**Discontinued
                operations, net of tax**
            
            
            **−**
            
            
            (4
            )
            
            59
            
            
            55**Net
                income (loss)**
            
            $
            275
            
            $
            82
            
            $
            (82
            )
            $
            275





44





Condensed
                Consolidating Statement of Income
              Three
                Months Ended March 31, 2006*(in
                millions)*
            
            **Parent**
            
            **Subsidiary
                Guarantor**
            
            **Other**
            
            **Progress
                Energy, Inc.****Operating
                revenues**Electric
            
            $
            **−**
            
            $
            1,007
            
            $
            978
            
            $
            1,985Diversified
                business
            
            
            **−**
            
            
            243
            
            
            (5
            )
            
            238**Total
                operating revenues**
            
            
            **−**
            
            
            1,250
            
            
            973
            
            
            2,223**Operating
                expenses**UtilityFuel
                used in electric generation
            
            
            **−**
            
            
            394
            
            
            296
            
            
            690Purchased
                power
            
            
            **−**
            
            
            165
            
            
            64
            
            
            229Operation
                and maintenance
            
            
            4
            
            
            166
            
            
            246
            
            
            416Depreciation
                and amortization
            
            
            **−**
            
            
            95
            
            
            133
            
            
            228Taxes
                other than on income
            
            
            **−**
            
            
            73
            
            
            46
            
            
            119Other
            
            
            **−**
            
            
            (3
            )
            
            1
            
            
            (2
            )Diversified
                businessCost
                of sales
            
            
            **−**
            
            
            244
            
            
            12
            
            
            256Depreciation
                and amortization
            
            
            **−**
            
            
            4
            
            
            5
            
            
            9Other
            
            
            **−**
            
            
            6
            
            
            4
            
            
            10**Total
                operating expenses**
            
            
            4
            
            
            1,144
            
            
            807
            
            
            1,955**Operating
                (loss) income**
            
            
            (4
            )
            
            106
            
            
            166
            
            
            268Other
                (expense) income, net
            
            
            (10
            )
            
            28
            
            
            (3
            )
            
            15Interest
                charges, net
            
            
            77
            
            
            48
            
            
            38
            
            
            163**(Loss)
                income from continuing operations before income tax, equity in earnings
                of
                consolidated subsidiaries and minority interest**
            
            
            (91
            )
            
            86
            
            
            125
            
            
            120**Income
                tax (benefit) expense**
            
            
            (33
            )
            
            19
            
            
            43
            
            
            29**Equity
                in earnings of consolidated subsidiaries**
            
            
            103
            
            
            **−**
            
            
            (103
            )
            
            **−****Minority
                interest in subsidiaries’ income, net of tax**
            
            
            **−**
            
            
            6
            
            
            **−**
            
            
            6**Income
                (loss) from continuing operations**
            
            
            45
            
            
            61
            
            
            (21
            )
            
            85**Discontinued
                operations, net of tax**
            
            
            **−**
            
            
            (1
            )
            
            (39
            )
            
            (40
            )**Net
                income (loss)**
            
            $
            45
            
            $
            60
            
            $
            (60
            )
            $
            45





45





Condensed
                Consolidating Balance Sheet
              March
                31, 2007*(in
                millions)*
            
            **Parent**
            
            **Subsidiary
                Guarantor**
            
            **Other**
            
            **Progress
                Energy, Inc.****Utility
                plant, net**
            
            $
            −
            
            $
            6,516
            
            $
            9,033
            
            $
            15,549**Current
                assets**Cash
                and cash equivalents
            
            
            10
            
            
            40
            
            
            83
            
            
            133Short-term
                investments
            
            
            −
            
            
            −
            
            
            1
            
            
            1Notes
                receivables from affiliated companies
            
            
            238
            
            
            −
            
            
            (238
            )
            
            −Deferred
                fuel cost
            
            
            −
            
            
            4
            
            
            185
            
            
            189Assets
                of discontinued operations
            
            
            −
            
            
            42
            
            
            853
            
            
            895Other
                current assets
            
            
            31
            
            
            1,095
            
            
            1,044
            
            
            2,170**Total
                current assets**
            
            
            279
            
            
            1,181
            
            
            1,928
            
            
            3,388**Deferred
                debits and other assets**Investment
                in consolidated subsidiaries
            
            
            11,035
            
            
            −
            
            
            (11,035
            )
            
            −Goodwill
            
            
            −
            
            
            1
            
            
            3,654
            
            
            3,655Other
                assets and deferred debits
            
            
            137
            
            
            1,503
            
            
            1,487
            
            
            3,127**Total
                deferred debits and other assets**
            
            
            11,172
            
            
            1,504
            
            
            (5,894
            )
            
            6,782**Total
                assets**
            
            $
            11,451
            
            $
            9,201
            
            $
            5,067
            
            $
            25,719**Capitalization**Common
                stock equity
            
            $
            8,501
            
            $
            2,798
            
            $
            (2,798
            )
            $
            8,501Preferred
                stock of subsidiaries - not subject to mandatory
                redemption
            
            
            −
            
            
            34
            
            
            59
            
            
            93Minority
                interest
            
            
            −
            
            
            50
            
            
            4
            
            
            54Long-term
                debt, affiliate
            
            
            −
            
            
            309
            
            
            (38
            )
            
            271Long-term
                debt, net
            
            
            2,595
            
            
            2,435
            
            
            3,482
            
            
            8,512**Total
                capitalization**
            
            
            11,096
            
            
            5,626
            
            
            709
            
            
            17,431**Current
                liabilities**Current
                portion of long-term debt
            
            
            −
            
            
            204
            
            
            200
            
            
            404Notes
                payable to affiliated companies
            
            
            −
            
            
            263
            
            
            (263
            )
            
            −Liabilities
                of discontinued operations
            
            
            −
            
            
            8
            
            
            171
            
            
            179Other
                current liabilities
            
            
            311
            
            
            993
            
            
            733
            
            
            2,037**Total
                current liabilities**
            
            
            311
            
            
            1,468
            
            
            841
            
            
            2,620**Deferred
                credits and other liabilities**Noncurrent
                income tax liabilities
            
            
            −
            
            
            57
            
            
            213
            
            
            270Regulatory
                liabilities
            
            
            −
            
            
            1,117
            
            
            1,467
            
            
            2,584Accrued
                pension and other benefits
            
            
            13
            
            
            377
            
            
            574
            
            
            964Other
                liabilities and deferred credits
            
            
            31
            
            
            556
            
            
            1,263
            
            
            1,850**Total
                deferred credits and other liabilities**
            
            
            44
            
            
            2,107
            
            
            3,517
            
            
            5,668**Total
                capitalization and liabilities**
            
            $
            11,451
            
            $
            9,201
            
            $
            5,067
            
            $
            25,719





46





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
                receivables 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





47





Condensed
                Consolidating Statement of Cash Flows
              Three
                Months Ended March 31, 2007*(in
                millions)*
            
            **Parent**
            
            **Subsidiary
                Guarantor**
            
            **Other**
            
            **Progress
                Energy, Inc.****Net
                cash (used) provided by operating activities**
            
            $
            (8
            )
            $
            33
            
            $
            244
            
            $
            269**Investing
                activities**Gross
                utility property additions
            
            
            −
            
            
            (261
            )
            
            (208
            )
            
            (469
            )Nuclear
                fuel additions
            
            
            −
            
            
            (23
            )
            
            (38
            )
            
            (61
            )Proceeds
                from sales of discontinued operations and other assets, net of cash
                divested
            
            
            −
            
            
            25
            
            
            5
            
            
            30Purchases
                of available-for-sale securities and other investments
            
            
            −
            
            
            (44
            )
            
            (148
            )
            
            (192
            )Proceeds
                from sales of available-for-sale securities and other
                investments
            
            
            21
            
            
            44
            
            
            187
            
            
            252Changes
                in advances to affiliates
            
            
            (180
            )
            
            37
            
            
            143
            
            
            −Other
                investing activities
            
            
            (2
            )
            
            (6
            )
            
            7
            
            
            (1
            )**Net
                cash used by investing activities**
            
            
            (161
            )
            
            (228
            )
            
            (52
            )
            
            (441
            )**Financing
                activities**Issuance
                of common stock
            
            
            65
            
            
            −
            
            
            −
            
            
            65Net
                increase in short-term debt
            
            
            117
            
            
            −
            
            
            −
            
            
            117Dividends
                paid on common stock
            
            
            (155
            )
            
            −
            
            
            −
            
            
            (155
            )Changes
                in advances from affiliates
            
            
            −
            
            
            187
            
            
            (187
            )
            
            −Other
                financing activities
            
            
            (1
            )
            
            11
            
            
            (43
            )
            
            (33
            )**Net
                cash provided (used) by financing activities**
            
            
            26
            
            
            198
            
            
            (230
            )
            
            (6
            )**Cash
                (used) provided by discontinued operations**Operating
                activities
            
            
            −
            
            
            (2
            )
            
            49
            
            
            47Investing
                activities
            
            
            −
            
            
            (1
            )
            
            −
            
            
            (1
            )Financing
                activities
            
            
            −
            
            
            −
            
            
            −
            
            
            −**Net
                (decrease) increase in cash and cash equivalents**
            
            
            (143
            )
            
            −
            
            
            11
            
            
            (132
            )**Cash
                and cash equivalents at beginning of period**
            
            
            153
            
            
            40
            
            
            72
            
            
            265**Cash
                and cash equivalents at end of period**
            
            $
            10
            
            $
            40
            
            $
            83
            
            $
            133





48





Condensed
                Consolidating Statement of Cash Flows
              Three
                Months Ended March 31, 2006*(in
                millions)*
            
            **Parent**
            
            **Subsidiary
                Guarantor**
            
            **Other**
            
            **Progress
                Energy, Inc.****Net
                cash provided by operating activities**
            
            $
            64
            
            $
            341
            
            $
            37
            
            $
            442**Investing
                activities**Gross
                utility property additions
            
            
            −
            
            
            (153
            )
            
            (151
            )
            
            (304
            )Nuclear
                fuel additions
            
            
            −
            
            
            (6
            )
            
            (46
            )
            
            (52
            )Proceeds
                from sales of discontinued operations and other assets, net of cash
                divested
            
            
            −
            
            
            98
            
            
            5
            
            
            103Purchases
                of available-for-sale securities and other investments
            
            
            (163
            )
            
            (126
            )
            
            (249
            )
            
            (538
            )Proceeds
                from sales of available-for-sale securities and other
                investments
            
            
            163
            
            
            71
            
            
            288
            
            
            522Changes
                in advances to affiliates
            
            
            135
            
            
            (66
            )
            
            (69
            )
            
            −Other
                investing activities
            
            
            (3
            )
            
            (3
            )
            
            (5
            )
            
            (11
            )**Net
                cash provided (used) by investing activities**
            
            
            132
            
            
            (185
            )
            
            (227
            )
            
            (280
            )**Financing
                activities**Issuance
                of common stock
            
            
            28
            
            
            −
            
            
            −
            
            
            28Proceeds
                from issuance of long-term debt, net
            
            
            397
            
            
            −
            
            
            −
            
            
            397Net
                increase (decrease) in short-term debt
            
            
            100
            
            
            −
            
            
            (21
            )
            
            79Retirement
                of long-term debt
            
            
            (800
            )
            
            (1
            )
            
            −
            
            
            (801
            )Dividends
                paid on common stock
            
            
            (151
            )
            
            −
            
            
            −
            
            
            (151
            )Dividends
                paid to parent
            
            
            −
            
            
            (59
            )
            
            59
            
            
            −Changes
                in advances from affiliates
            
            
            −
            
            
            (127
            )
            
            127
            
            
            −Other
                financing activities
            
            
            (5
            )
            
            (24
            )
            
            (31
            )
            
            (60
            )**Net
                cash (used) provided by financing activities**
            
            
            (431
            )
            
            (211
            )
            
            134
            
            
            (508
            )**Cash
                provided (used) by discontinued operations**Operating
                activities
            
            
            −
            
            
            16
            
            
            38
            
            
            54Investing
                activities
            
            
            −
            
            
            (49
            )
            
            (1
            )
            
            (50
            )Financing
                activities
            
            
            −
            
            
            −
            
            
            −
            
            
            −**Net
                decrease in cash and cash equivalents**
            
            
            (235
            )
            
            (88
            )
            
            (19
            )
            
            (342
            )**Cash
                and cash equivalents at beginning of period**
            
            
            239
            
            
            239
            
            
            127
            
            
            605**Cash
                and cash equivalents at end of period**
            
            $
            4
            
            $
            151
            
            $
            108
            
            $
            263







49


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).
      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 term “Progress
      Registrants” refers to each of the three separate registrants: Progress Energy,
      PEC and PEF.




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” 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 seasonal temperature variations on energy consumption and the timing of
      maintenance on electric generating 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;


·
            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 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 months ended March 31, 2007 are
      compared to the same period 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.




50


**Overview**




For
      the
      quarter ended March 31, 2007, our net income was $275 million, or $1.08 per
      share, compared to net income of $45 million, or $0.18 per share, for the same
      period in 2006. For the quarter ended March 31, 2007, our income from continuing
      operations was $220 million compared to $85 million for the same period in
      2006.
      The increase in income from continuing operations as compared to prior year
      was
      primarily due to:





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


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


·
            higher
                tax credits due to higher synthetic fuels
                production;


·
            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
                operating and maintenance (O&M) expenses due to the impact of
                recording additional estimated environmental remediation expenses
                at PEC
                in 2006;


·
            lower
                interest expense due to reducing holding company debt during 2006;
                and


·
            higher
                retail base revenue at PEC primarily due to the impact of favorable
                growth
                and usage and weather.





Partially
      offsetting these items was:





·
            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).





Our
      segments contributed the following profits or losses for the three months ended
      March 31, 2007 and 2006:


Three
                Months Ended March 31,*(in
                millions)*
            
            **2007**
            
            2006Business
                SegmentPEC
            
            **$**
            **123**
            
            $
            85PEF
            
            
            **60**
            
            
            52Coal
                and Synthetic Fuels
            
            
            **57**
            
            
            9Total
                segment profit
            
            
            **240**
            
            
            146Corporate
                and Other
            
            
            **(20**
            **)**
            
            (61
            )Income
                from continuing operations
            
            
            **220**
            
            
            85Discontinued
                operations, net of tax
            
            
            **55**
            
            
            (40
            )Net
                income
            
            **$**
            **275**
            
            $
            45





**Progress
      Energy Carolinas**




PEC
      contributed segment profits of $123 million and $85 million for the three months
      ended March 31, 2007 and 2006, respectively. The increase in profits for the
      three months ended March 31, 2007, when compared to 2006, was primarily due
      to
      lower O&M expenses related to the impact of recording additional
      environmental remediation expenses in 2006, favorable retail customer growth
      and
      usage and favorable weather partially offset by higher income tax
      expense.




51


**REVENUES**




PEC’s
      revenues for the three months ended March 31, 2007 and 2006, and the percentage
      change by customer class were as follows:


*(in
                millions)*
            
            Three
                Months Ended March 31,Customer
                Class
            
            **2007**
            
            Change
            
            %
                Change
            
            2006Residential
            
            **$**
            **424**
            
            $
            48
            
            
            12.8
            
            $
            376Commercial
            
            
            **254**
            
            
            28
            
            
            12.4
            
            
            226Industrial
            
            
            **165**
            
            
            2
            
            
            1.2
            
            
            163Governmental
            
            
            **22**
            
            
            2
            
            
            10.0
            
            
            20Total
                retail revenues
            
            
            **865**
            
            
            80
            
            
            10.2
            
            
            785Wholesale
            
            
            **194**
            
            
            2
            
            
            1.0
            
            
            192Unbilled
            
            
            **(25**
            **)**
            
            2
            
            
            -
            
            
            (27
            )Miscellaneous
            
            
            **23**
            
            
            (5
            )
            
            (17.9
            )
            
            28Total
                electric revenues
            
            
            **1,057**
            
            
            79
            
            
            8.1
            
            
            978Less:
                Fuel revenues
            
            
            **(375**
            **)**
            
            (58
            )
            
            -
            
            
            (317
            )Revenues
                excluding fuel
            
            **$**
            **682**
            
            $
            21
            
            
            3.2
            
            $
            661





PEC’s
      energy sales for the three months ended March 31, 2007 and 2006, and the amount
      and percentage change by customer class were as follows:


*(in
                millions of kWh)*
            
            Three
                Months Ended March 31,Customer
                Class
            
            **2007**
            
            Change
            
            %
                Change
            
            2006Residential
            
            
            **4,740**
            
            
            323
            
            
            7.3
            
            
            4,417Commercial
            
            
            **3,245**
            
            
            193
            
            
            6.3
            
            
            3,052Industrial
            
            
            **2,821**
            
            
            (112
            )
            
            (3.8
            )
            
            2,933Governmental
            
            
            **327**
            
            
            7
            
            
            2.2
            
            
            320Total
                retail energy sales
            
            
            **11,133**
            
            
            411
            
            
            3.8
            
            
            10,722Wholesale
            
            
            **3,956**
            
            
            (2
            )
            
            (0.1
            )
            
            3,958Unbilled
            
            
            **(343**
            **)**
            
            35
            
            
            -
            
            
            (378
            )Total
                kWh sales
            
            
            **14,746**
            
            
            444
            
            
            3.1
            
            
            14,302





PEC’s
      revenues, excluding fuel revenues of $375 million and $317 million for the
      three
      months ended March 31, 2007 and 2006, respectively, increased $21 million.
      The
      increase in revenues is primarily due to favorable retail growth and usage
      and
      favorable weather partially offset by a decrease in miscellaneous revenues.
      Favorable retail growth and usage of $15 m illion
      was driven by both an increase in the average usage per retail
      customer and an
      approximate increase in the average number of customers of 28,000 as of March
      31, 2007, compared to March 31, 2006. The impact of weather was $9 million
      favorable with heating degree days 3 percent higher than 2006 and cooling degree
      days 93 percent higher than 2006. The decrease in miscellaneous revenues was
      primarily due to lower gains on forward sales of excess generation during 2007
      as compared to 2006.




**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 $409 million for the three months ended March
      31,
      2007, which represents a $49 million increase compared to the same period in
      2006. Fuel used in electric generation increased $55 million to $351 million
      compared to the prior year. This increase is due to a $35 million increase
      in
      fuel used in generation primarily due to a change in generation mix as the
      percentage of generation supplied by natural gas increased in




52


response
      to higher system requirements due to cold weather in February 2007. A $20
      million increase in deferred fuel expense primarily due to an increase in the
      fuel recovery rates for North Carolina, also contributed to the increase in
      fuel
      expense. Current year purchased power costs were $6 million lower than the
      three
      months ended March 31, 2006, due to lower cogeneration as a result of contract
      changes with one of our co-generators.




**Operation
      and Maintenance**




O&M
      expenses were $248 million for the three months ended March 31, 2007, which
      represents an $8 million decrease compared to the same period in 2006. O&M
      expenses decreased $23 million due to recording additional estimated
      environmental remediation expenses during 2006 (See Note 11A). This was
      partially offset by $8 million of higher outage costs, $3 million of incremental
      labor costs due to filling vacant positions and $2 million of higher costs
      related to the operation of emission control equipment installed at our
      coal-fired plants.




**Depreciation
      and Amortization**




Depreciation
      and amortization expense was $117 million for the three months ended March
      31,
      2007, which represents a $9 million decrease compared to the same period in
      2006. Depreciation expense decreased $14 million due to lower North Carolina
      Clean Smokestacks Act (Clean Smokestacks Act) amortization, partially offset
      by
      the impact of depreciable asset base increases.




**Taxes
      other than on Income**




Taxes
      other than on income was $50 million for the three months ended March 31, 2007,
      which represents a $4 million increase compared to the same period in 2006.
      The
      increase is primarily due to a $3 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 $9 million increased $3 million for the three months ended
      March
      31, 2007, compared to the same period in 2006, primarily due to a $2 million
      gain on the sale of investments during 2007 and a $1 million increase in the
      equity component of allowance for funds used during construction
      (AFUDC).




**Income
      Tax Expense**




Income
      tax expense increased $11 million for the three months ended March 31, 2007,
      as
      compared to the same period in 2006, primarily due to the $20 million impact
      of
      higher earnings compared to the prior year. This was partially offset by $5
      million of favorable changes related to prior year federal and state income
      tax
      returns and a $3 million favorable change related to tax levelization. GAAP
      requires companies to apply a levelized effective tax rate to interim periods
      that is consistent with the estimated annual effective tax rate. PEC’s income
      tax expense was reduced $1 million for the three months ended March 31, 2007
      compared to an increase of $2 million for the three months ended March 31,
      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 and temporary deductions 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.




53


**Progress
      Energy Florida**




PEF
      contributed segment profits of $60 million and $52 million for the three months
      ended March 31, 2007 and 2006, respectively. The increase in profits for the
      three months ended March 31, 2007, when compared to 2006, was primarily due
      to
      higher wholesale revenues and other miscellaneous service revenues.




**REVENUES**




PEF’s
      revenues for the three months ended March 31, 2007 and 2006, and the amount
      and
      percentage change by customer class were as follows:


*(in
                millions**)*
            
            Three
                Months Ended March 31,Customer
                Class
            
            **2007**
            
            Change
            
            %
                Change
            
            2006Residential
            
            **$**
            **491**
            
            $
            (15
            )
            
            (3.0
            )
            $
            506Commercial
            
            
            **247**
            
            
            2
            
            
            0.8
            
            
            245Industrial
            
            
            **74**
            
            
            (9
            )
            
            (10.8
            )
            
            83Governmental
            
            
            **67**
            
            
            1
            
            
            1.5
            
            
            66Retail
                revenue sharing
            
            
            -
            
            
            (1
            )
            
            -
            
            
            1Total
                retail revenues
            
            
            **879**
            
            
            (22
            )
            
            (2.4
            )
            
            901Wholesale
            
            
            **80**
            
            
            11
            
            
            15.9
            
            
            69Unbilled
            
            
            **8**
            
            
            7
            
            
            -
            
            
            1Miscellaneous
            
            
            **44**
            
            
            8
            
            
            22.2
            
            
            36Total
                electric revenues
            
            
            **1,011**
            
            
            4
            
            
            0.4
            
            
            1,007Less:
                Fuel and other pass-through revenues
            
            
            **(645**
            **)**
            
            9
            
            
            -
            
            
            (654
            )Revenues
                excluding fuel and other pass-through revenues
            
            **$**
            **366**
            
            $
            13
            
            
            3.7
            
            $
            353





PEF’s
      electric energy sales for the three months ended March 31, 2007 and 2006, and
      the amount and percentage change by customer class are as follows:


*(in
                millions of kWh)*
            
            Three
                Months Ended March 31,Customer
                Class
            
            **2007**
            
            Change
            
            %
                Change
            
            2006Residential
            
            
            **4,155**
            
            
            (156
            )
            
            (3.6
            )
            
            4,311Commercial
            
            
            **2,624**
            
            
            74
            
            
            2.9
            
            
            2,550Industrial
            
            
            **895**
            
            
            (111
            )
            
            (11.0
            )
            
            1,006Governmental
            
            
            **748**
            
            
            27
            
            
            3.7
            
            
            721Total
                retail energy sales
            
            
            **8,422**
            
            
            (166
            )
            
            (1.9
            )
            
            8,588Wholesale
            
            
            **1,170**
            
            
            163
            
            
            16.2
            
            
            1,007Unbilled
            
            
            **190**
            
            
            340
            
            
            -
            
            
            (150
            )Total
                kWh sales
            
            
            **9,782**
            
            
            337
            
            
            3.6
            
            
            9,445





PEF’s
      revenues, excluding recoverable fuel and other pass-through revenues of $645
      million and $654 million for the three months ended March 31, 2007 and 2006,
      respectively, increased $13 million. The increase in revenues is primarily
      due
      to increased wholesale revenues and other miscellaneous service revenues.
      Wholesale revenues increased primarily due to the $7 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 $4 million. Industrial revenues and sales have decreased primarily due to
      a
      change in the service provided to a large customer; however, this decrease
      has
      been partially offset by a reduction in the associated purchased power expense
      and therefore has no material impact on earnings. Although overall growth and
      usage did not have a material impact on revenues, favorable growth of $5 million
      driven by an approximate average net increase in the number of customers of
      31,000 as of March 31, 2007, compared to March 31, 2006 was offset by lower
      usage per customer.




54


**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 $548 million for the three months ended March
      31,
      2007, which represents an $11 million decrease compared to the same period
      in
      2006. This decrease is due to decreases in fuel used in electric generation
      and
      purchased power expenses of $9 million and $2 million, respectively. Fuel used
      in electric generation decreased primarily due to lower deferred fuel expense
      of
      $44 million partially offset by increased current year fuel costs of $36
      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 decrease in purchased power expense was primarily due to lower
      recovery of deferred capacity costs.




**Operation
      and Maintenance**




O&M
      expenses were $175 million for the three months ended March 31, 2007, which
      represents a $9 million increase, when compared to the same period in 2006.
      O&M expenses increased $8 million related to higher environmental cost
      recovery (ECRC) and higher energy conservation cost recovery (ECCR) costs.
      The
      ECRC and ECCR expenses are recovered through cost-recovery clauses and,
      therefore, have no material impact on earnings.




**Total
      Other Income**




Total
      other income of $8 million increased $4 million for the three months ended
      March
      31, 2007 compared to the same period in 2006, primarily due to a $5 million
      increase in AFUDC equity related to costs associated with large construction
      projects partially offset by lower interest income. Interest income decreased
      due primarily to lower short-term investment balances and lower interest on
      unrecovered storm restoration costs. We expect AFUDC equity to continue to
      increase during 2007.




**Income
      Tax Expense**




Income
      tax expense decreased $2 million for the three months ended March 31, 2007,
      as
      compared to the same period in 2006, primarily due to the impact of the increase
      in AFUDC equity discussed above and current year miscellaneous tax adjustments.
      AFUDC equity is excluded from the calculation of income tax
      expense.




**Coal
      a****nd Synthetic Fuels**




The
      operations of the Coal and Synthetic Fuels segment include synthetic fuels
      production and coal terminal operations. The following summarizes the Coal
      and
      Synthetic Fuels segment profits:


Three
                Months Ended March 31,*(in
                millions)*
            
            **2007**
            
            2006Synthetic
                fuels operations
            
            **$**
            **62**
            
            $
            3Coal
                terminals and marketing
            
            
            **(2**
            **)**
            
            14Corporate
                overhead and other operations
            
            
            **(3**
            **)**
            
            (8
            )Segment
                profits
            
            **$**
            **57**
            
            $
            9





55


**SYNTHETIC
      FUELS OPERATIONS**




The
      production and sale of 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 March 31,*(in
                millions)*
            
            **2007**
            
            2006Tons
                sold
            
            
            **2.1**
            
            
            1.2After-tax
                profits (losses) (excluding tax credits)
            
            **$**
            **10**
            
            $
            (26
            )Tax
                credits generated
            
            
            **61**
            
            
            35Tax
                credit inflation adjustment
            
            
            **-**
            
            
            10Tax
                credits reserve increase due to estimated phase-out
            
            
            **(9**
            **)**
            
            (16
            )Net
                profit
            
            **$**
            **62**
            
            $
            3





Synthetic
      fuels operations’ net profit increased $59 million for the three months ended
      March 31, 2007, as compared to the same period in 2006. After-tax profits
      (excluding tax credits) for synthetic fuels operations increased $36 million
      for
      the three months ended March 31, 2007 compared to the same period in 2006
      primarily due to the $29 million unrealized after-tax mark-to-market gain
      recorded on derivative contracts entered into in January 2007 (See Note 8A).
      After-tax profits (excluding tax credits) were also positively impacted by
      lower
      royalty expenses and lower depreciation expense both due to the second quarter
      2006 impairment of our synthetic fuel assets. These were partially offset by
      lower margins due to the increase in synthetic fuels production. Tax credits
      generated during the three months ended March 31, 2007 compared to the same
      period in 2006 increased due to higher production. We increased synthetic fuels
      production in 2007 as a result of lower current year oil prices, lower futures
      prices based on the oil futures curve which reduced the potential tax credit
      phase-out and the protection against oil price increases provided by the
      derivative contracts. The change in the tax credit reserve is primarily due
      to
      the change in the relative level of oil prices which indicated an estimated
      phase-out of 18 percent in 2007 compared to an estimated phase-out of 47 percent
      in 2006. The 2007 tax credit reserve increase includes $11 million due to the
      potential phase-out of the 2007 tax credits partially offset by the reversal
      of
      $2 million of credits reserved in 2006. 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 lower than our
      December 31, 2006 phase-out estimate of 35 percent.




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
      unrelated third-party buyer (see Note 3H and “Other Matters - Synthetic Fuels
      Tax Credits”). We will continue 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
      anticipate recording a 100 percent minority interest and anticipate that there
      will be no net earnings impact. Consequently, future net operating results
      and
      tax credits generated by Ceredo will be excluded from our Coal and Synthetic
      Fuels segment. A portion of the derivative contracts discussed above were
      entered into by Ceredo and contributed $10 million of the total $29 million
      unrealized after-tax mark-to-market gain recorded for the three months ended
      March 31, 2007. Future mark-to-market changes on the Ceredo portion of the
      derivative contracts will also be excluded from the results of our Coal and
      Synthetic Fuels segment.




Our
      synthetic fuels production levels for 2007 remain uncertain due to the recent
      volatility of oil prices. See “Other Matters - Synthetic Fuels Tax Credits”
below for additional information on the impact of oil prices on Section 29/45K
      tax credits and a discussion of uncertainties surrounding our synthetic fuels
      production in 2007.




**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 procuring
      and
      processing of coal and the transloading and marketing of synthetic fuels. 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. Coal operations had losses of $2 million for the
      three months ended




56


March
      31,
      2007 compared to earnings of $14 million for the same period in 2006. Coal’s
      2007 results were negatively impacted by a decrease in sales to external
      customers and the prior year impact of the $11 million pre-tax expense reduction
      due to restructuring a coal supply contract in 2006.




**CORPORATE
      OVERHEAD AND OTHER OPERATIONS**




Corporate
      overhead and other operations incurred losses of $3 million and $8 million
      for
      the three months ended March 31, 2007 and 2006, respectively. The decrease
      in
      losses for 2007 compared to 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
      a****nd 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 March 31,*(in
                millions)*
            
            **2007**
            
            2006Other
                interest expense
            
            **$**
            **(48**
            **)**
            $
            (64
            )Contingent
                value obligations
            
            
            **1**
            
            
            (25
            )Tax
                levelization
            
            
            **7**
            
            
            (14
            )Other
                income tax benefit
            
            
            **20**
            
            
            26Other
            
            
            **-**
            
            
            16Corporate
                and Other after-tax expense
            
            **$**
            **(20**
            **)**
            $
            (61
            )





Other
      interest expense decreased $16 million for the three months ended March 31,
      2007
      compared to the same period in 2006 primarily due to the $1.7 billion reduction
      in holding company debt during 2006 partially offset by a decrease in the
      interest allocated to discontinued operations. The decrease in interest expense
      allocated to discontinued operations resulted from the allocations of interest
      expense in early 2006 for operations that were sold later in 2006.




Progress
      Energy issued 98.6 million contingent value obligations (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 March 31,
      2007
      and 2006, the CVOs had fair market values of approximately $ 31 million
      and $33 million, respectively. Progress Energy recorded unrealized gains of
      $ 1 million
      for the three months ended March 31, 2007 and unrealized losses of $25 million
      for the three months ended March 31, 2006, to record the changes in fair value
      of the CVOs, which had average unit prices of $ 0.31 and
      $ 0.33 at March
      31, 2007 and 2006, respectively.




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 $7 million for the three months ended March 31, 2007
      compared to an increase of $14 million for the three months ended March 31,
      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
      decreased $16 million primarily due to the $13 million gain, net of minority
      interest, on the sale of Level 3 Communications, Inc. (Level 3) stock subsequent
      to the sale of PT LLC in 2006 (See Note 3D).




57


**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 Operations**




On
      March
      9, 2007, our subsidiary, Progress Ventures, Inc. (PVI), entered into a series
      of
      transactions to sell substantially all of its CCO physical and commercial assets
      and liabilities. Assets to be divested include 1,900 megawatts (MW) of gas-fired
      generation assets in Georgia. The sale of the generation assets is expected
      to
      close in the summer of 2007 for a net sales price of $603 million and is subject
      to federal regulatory approvals and customary closing conditions. 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 noncash impairment recorded in 2006.




Additionally,
      PVI has agreed, subject to obtaining federal regulatory approvals, customer
      consents and customary closing conditions, to assign the CCO 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. As a result of the
      assignment, PVI will make a net cash payment of $347 million, which will
      represent the net cost to assign the Georgia Contracts and other related
      contracts. As of March 31, 2007, we estimated, as a result of the assignments,
      the charge associated with exit costs will be in excess of $320 million
      after-tax. The actual amount of the exit costs to be recorded may vary based
      on
      changes in commodity prices. However, any variation in the estimated exit costs
      will have an offsetting impact in net earnings from discontinued operations.
      The
      contract assignment agreement is expected to close in the summer of 2007.




We
      estimate pre-tax net proceeds on these transactions to be $256 million
      (approximately $476 million after estimated tax benefits.) Proceeds will be
      used
      for general corporate purposes (see Note 3A).




CCO’s
      operations generated net earnings from discontinued operations of $43 million
      for the three months ended March 31, 2007 compared to net losses from
      discontinued operations of $60 million for the same period in 2006. The change
      in earnings for 2007 compared to 2006 is primarily due to a $52 million
      after-tax increase in unrealized mark-to-market gains, primarily related to
      the
      increase in natural gas prices in 2007 compared to 2006, and the impact of
      the
      $39 million after-tax impairment of goodwill recorded in 2006. In addition,
      earnings increased due to realized mark-to-market gains due to favorable changes
      in gas and power prices and favorable margins on our Georgia contracts due
      to
      serving an increased load at higher rates.




**CCO
      - DeSoto and Rowan Generation Facilities**




On
      May 2,
      2006, our board of directors approved a plan to divest of PVI’s subsidiaries,
      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 a gross purchase price of approximately $80 million
      and
      $325 million, respectively. We used the proceeds from the sales to reduce debt
      and for other corporate purposes (See Note 3C).




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 of $67 million
      during the year ended December 31, 2006, on the sale of DeSoto and Rowan.
      Discontinued DeSoto and Rowan operations had combined losses of $3 million
      for
      the three months ended March 31, 2006.




58


**GAS
      OPERATIONS**




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 Corporation (Progress Fuels). Proceeds
      from the sale have been used primarily to reduce holding company debt and for
      other corporate purposes (See Note 3B).




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 $21 million
      for the three months ended March 31, 2006.




**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 $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 3D).




Based
      on
      the net proceeds associated with the sale and after consideration of minority
      interest, we recorded an estimated after-tax gain on disposal of $24 million
      during the three months ended March 31, 2006. Net loss from discontinued
      operations for PT LLC was $6 million for the three months ended March 31,
      2006.




**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 under long-term contracts with
      PEF.
      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 other fuels business is expected to
      be
      sold in 2007 (See Note 3E).




Net
      earnings from discontinued operations for Dixie Fuels and other fuels business
      were $1 million and $2 million for the three months ended March 31, 2007 and
      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. 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 three months ended March
      31,
      2006, we recorded an estimated after-tax loss of $15 million for the sale of
      these assets. The remaining coal mining operations are expected to be sold
      in
      2007 (See Note 3F).




Net
      losses from discontinued operations for the coal mining business were $4 million
      and $5 million for the three months ended March 31, 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’




59


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 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 and employee benefit
      and
      stock option plans are expected to fund capital expenditures, common stock
      dividends, and debt service for 2007. For the fiscal year 2007, we expect to
      realize an aggregate amount of approximately $130 million from the sale of
      stock
      through these plans.





We
      believe our internal and external liquidity resources will be sufficient to
      fund
      our current business plans. Risk factors associated with credit facilities
      and
      credit ratings are discussed in the “Risk Factors” section in the 2006 Form
      10-K.




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




**Historical
      for 2007 as 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 $173 million for the three months ended March 31, 2007,
      when compared to the corresponding period in the prior year. The decrease in
      operating cash flow was primarily due to a $64 million decrease from the change
      in accounts receivable, primarily at PEC, $65 million in premiums paid for
      derivative contracts (see Note 8A), and approximately $100 million related
      to
      income tax payments, largely driven by the sale of Gas. These impacts were
      partially offset by $47 million in net refunds of cash collateral previously
      paid to counterparties on derivative contracts at PEF.




**INVESTING
      ACTIVITIES**




Net
      cash
      used in investing activities increased by $161 million for the three months
      ended March 31, 2007, when compared to the corresponding period in the prior
      year. This is due primarily to a $165 million increase in capital expenditures
      for utility property and a $73 million decrease in proceeds from sales of
      discontinued operations and other assets, partially offset by a $76 million
      decrease in net purchases of short-term investments included in
      available-for-sale securities and other investments. 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 steam production projects, partially offset by lower spending at
      the Hines Unit 4 facility. 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 three months ended March 31, 2007, proceeds from sales of discontinued
      operations and other assets primarily included working capital adjustments
      for
      Gas and the sale of poles at Progress Telecommunications




60


Corporation.
      During the three months ended March 31, 2006, proceeds from sales of
      discontinued operations and other assets primarily included $70 million in
      cash
      proceeds from the sale of PT LLC (See Note 3D) and approximately $15 million
      in
      net cash proceeds from the sale of Dixie Fuels, net of cash divested (See Note
      3E).




**FINANCING
      ACTIVITIES**




Net
      cash
      used in financing activities was $6 million for the three months ended March
      31,
      2007, compared to net cash used by financing activities of $508 million for
      the
      three months ended March 31, 2006, for a net decrease of $502 million. The
      change in cash used in financing activities was due primarily to 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,
      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.




At
      December 31, 2006, we had 500 million shares of common stock authorized under
      our charter, of which approximately 256 million were outstanding. For the three
      months ended March 31, 2007 and 2006, respectively, we issued approximately
      1.5
      million shares and 0.7 million shares of common stock resulting in approximately
      $65 million and $28 million in proceeds. Included in these amounts were
      approximately 0.2 million shares and 0.3 million shares for proceeds of
      approximately $11 million and $14 million, respectively, to meet the
      requirements of the Progress Energy 401(k) Savings and Stock Ownership Plan
      (401(k)) and the Investor Plus Stock Purchase Plan.




**Future
      Liquidity and Capital Resources**




At
      March
      31, 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.
      It
      is expected 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 do not currently produce positive operating cash
      flow
      due to the difference in timing of when tax credits are recognized for financial
      reporting purposes and when tax credits are realized for tax purposes (See
      “Other Matters - Synthetic Fuels Tax Credits”).




Cash
      from
      operations plus availability under our credit facilities and shelf registration
      statements is expected to be sufficient to meet our requirements in the near
      term. To the extent necessary, we may also use limited ongoing equity sales
      from
      our Investor Plus Stock Purchase Plan and employee benefit and stock option
      plans to meet our liquidity requirements.




Over
      the
      long term, meeting the anticipated load growth at the Utilities will require
      the
      Utilities to make significant capital investments. These anticipated capital
      investments are expected 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.




As
      of
      March 31, 2007, the current portion of our long-term debt was $404 million,
      which we expect to fund with cash from operations, proceeds from sales of
      assets, commercial paper borrowings and/or long-term debt issuances. See Note
      3
      for additional information on asset sales.




61


**CREDIT
      RATING MATTERS**




On
      March
      15, 2007, Standard & Poor’s Rating Services (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 11 and
      in
“Other Matters - Environmental Matters,” in 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.




**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. 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 customers. PEC is
      asking the SCPSC to approve a $12 million increase in rates. PEC requested
      the
      increase for underrecovered fuel costs associated with prior year settlements
      and to meet future expected fuel costs. If approved, the increase would take
      effect July 1, 2007 and would increase residential electric bills by $1.76
      per
      1,000 kilowatt hours (kWhs), or 1.9 percent, for fuel cost recovery. A hearing
      on the matter has been scheduled by the SCPSC for June 13, 2007. We cannot
      predict the outcome of this matter.




**PEF
      Pass-through Clause Cost Recovery**




On
      August
      10, 2006, Florida’s Office of Public Counsel (OPC) filed a petition with the
      Florida Public Service Commission (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 (SO 2 )
      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. The FPSC held a hearing on the matter from
      April
      2 through April 5, 2007. We anticipate that the FPSC will reach a decision
      on
      this matter later in 2007. PEF believes that its coal procurement practices
      were
      prudent and that it has sound legal and factual arguments to successfully defend
      its position. We cannot predict the outcome of this matter.




On
      February 8, 2007, the FPSC issued an order approving PEF’s request for a need
      determination to uprate Crystal River Unit No. 3 Nuclear Plant (CR3) 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 uprate costs should be recovered
      through the fuel recovery clause. On May 4, 2007, PEF filed amended testimony
      clarifying the scope of the project. The FPSC has scheduled an August 7, 2007,
      hearing on this matter. If PEF does not receive approval to recover the uprate
      costs through the fuel recovery clause, these costs will be recoverable through
      base rates, similar to other utility plant additions. We cannot predict the
      outcome of this matter.




62


**Other
      Regulatory Matters**




PEF
      filed
      a cost-recovery petition with the FPSC on April 30, 2007, to recover the current
      estimate of in-service cost of Hines Unit 4 through a base rate increase, as
      provided for by PEF’s base rate agreement. The base rate increase would be
      effective upon placing Hines Unit 4 in service, which PEF anticipates will
      be on
      December 1, 2007.




As
      discussed further in “Other Matters - Regulatory Environment”, new South
      Carolina energy legislation that became law on May 2, 2007 may impact our
      liquidity in the future. PEC cannot determine at this time how the final rules
      and regulation resulting from this legislation will impact its operations and
      financial condition.




**OFF-BALANCE
      SHEET ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS**




Our
      off-balance sheet arrangements and contractual obligations are described below.




**G****uarantees**




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
      March
      31, 2007, we have issued $1.481 billion of guarantees for future financial
      or
      performance assurance, including $83 million at PEC, $2 million at PEF and
      approximately $900 million related to CCO. Included in this amount is $300
      million of guarantees of certain payments of two wholly owned indirect
      subsidiaries issued by the Parent (See Note 13). 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 Investors Service, Inc. (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 March 31, 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 approximate amount of liquidity
      requirements to support ongoing operations within a 90-day period, associated
      with guarantees for Progress Energy’s nonregulated portfolio and power supply
      agreements, was $548 million at March 31, 2007. While we believe that we would
      be able to meet this obligation with cash or letters of credit, if we cannot,
      our financial condition, liquidity and results of operations will be materially
      and adversely impacted.




At
      March
      31, 2007, we have issued guarantees and indemnifications of certain asset
      performance, legal, tax and environmental matters to third parties, including
      indemnifications made in connection with sales of businesses, and for timely
      payment of obligations in support of our nonwholly owned synthetic fuels
      operations as discussed in Note 12A.




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




63


**Contractual
      Obligations**




As
      of
      March 31, 2007, our contractual cash obligations and other commercial
      commitments have not changed materially from what was reported in the 2006
      Form
      10-K.




**OTHER
      MATTERS**




**S****ynthetic
      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.




**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 synthetic fuels
      than we have historically produced, should we choose to do so.




Total
      Section 29/45K credits generated through March 31, 2007 (including those
      generated by Florida Progress Corporation (Florida Progress) prior to our
      acquisition), were approximately $1.884 billion, of which $1.075 billion has
      been used to offset regular federal income tax liability, $798 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 $11
      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 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, there was a 33
      percent, or approximately $35 million, reduction of our synthetic fuels tax
      credits generated during 2006.




64


We
      estimate that the 2007 Threshold Price will be approximately $56 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 $7 lower than
      the
      corresponding daily New York Mercantile Exchange (NYMEX) prompt month settlement
      price for light sweet crude oil. Through March 31, 2007, the average NYMEX
      settlement price for light sweet crude oil was $58.23 per barrel, and as of
      March 31, 2007, the average NYMEX futures price for light sweet crude oil for
      the remainder of calendar year 2007 was $67.46 per barrel. This results in
      a
      weighted-average annual price for light sweet crude oil of approximately $65.25
      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 $65.25 per barrel for the entire year in 2007, we currently
      estimate that the synthetic fuels tax credit amount for 2007 would be reduced
      by
      approximately 18 percent. Therefore, we reserved 18 percent or approximately
      $11
      million of the $61 million of tax credits generated during the first quarter
      of
      2007. The NYMEX price of oil for the remainder of 2007 would have to be $64.01
      to have no reduction in value of tax credits generated during 2007 and would
      have to be $82.86 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 may cause quarterly adjustments to our results of operations and
      the
      amount of tax credits we record or reserve, either positive or negative,
      depending on current and futures oil prices at the end of the quarter, which
      impact the estimated weighted average annual price of oil for 2007.




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 3H, we disposed of our 100 percent ownership interest in Ceredo
      in
      March 2007. Our synthetic fuels production levels for 2007 remain uncertain
      because we cannot predict with any certainty the Annual Average Price of oil
      for
      2007. We will continue to monitor the environment surrounding synthetic fuels
      production and will adjust our production as warranted by changing conditions.
      See Note 8 and Item 3, “Quantitative and Qualitative Disclosures About Market
      Risk,” for a discussion of market risk and derivatives.




**SALE****S
      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 qualifying synthetic
      fuels, to an unrelated 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 will be received as we produce and sell qualified
      synthetic fuels on behalf of the buyer during 2007. Actual proceeds could differ
      based on actual production levels, which shall be determined by the buyer.
      The
      estimated production level of Ceredo is 2.8 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 from the disposal will be recognized over
      time as we produce and sell qualified synthetic fuels for the buyer. The
      reconfirmation private letter ruling request has been submitted to the IRS.
      Subsequent to the disposal, we remain the primary beneficiary of Ceredo and
      will
      continue to consolidate Ceredo in accordance with FIN 46R, but we anticipate
      recording a 100 percent minority interest. Consequently, we anticipate that
      there will be no net earnings impact. 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 the deferred gain. The ultimate
      resolution of these matters could result in adjustments to the gain on disposal
      in future periods. See Note 3H for additional discussion of this transaction
      and
      Note 12A 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 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




65


proceeds
      have become fixed or determinable and collectability is reasonably assured.
      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 the gain recognition criteria are met, gains from selling interests in
      Colona will be deferred. It is possible that gains will be deferred to
      subsequent quarters, or to a subsequent calendar year, until there is persuasive
      evidence that no tax credit phase-out will occur for the applicable 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 March 31,
      2007, a pre-tax gain on monetization of $12 million has been deferred. Based
      on
      the current level of oil prices, we cannot predict how much of this gain will
      be
      recognized in 2007. Beginning with the payment for the second quarter of 2006,
      the minority interest parties have elected to defer their cash payments in
      consideration of the idling of the synthetic fuels facilities at that time.
      In
      consideration of the resumption of limited synthetic fuels production in the
      fourth quarter of 2006, the minority interest parties made a partial payment
      in
      January 2007.




See
      Note
      12B 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.




PEC
      and
      PEF continue to monitor developments impacting retail competition in their
      respective service territories. Movement toward deregulation throughout the
      nation has effectively ceased due to numerous factors including, but not limited
      to, California’s experience with retail deregulation. To our knowledge, there is
      currently no enacted or proposed legislation in North Carolina, South Carolina
      or Florida that would give retail customers 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.




The
      South
      Carolina legislature ratified new energy legislation on April 26, 2007, which
      became law on May 2, 2007. Key elements of the legislation include expansion
      of
      the annual fuel clause mechanism to include recovery of the costs of reagents
      (ammonia, limestone, etc.) used in the operation of PEC’s emissions control
      technologies. The legislation also includes provisions to provide cost-recovery
      mechanisms for upfront development costs associated with nuclear baseload
      generation, cost-recovery mechanisms for construction costs associated with
      nuclear or coal baseload generation and the ability to recover financing costs
      for new nuclear baseload generation through annual riders. PEC cannot determine
      at this time how the final rules and regulations resulting from this legislation
      will impact its operations and financial condition.




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.




**Legal**




We
      are
      subject to federal, state and local legislation and court orders. These matters
      are discussed in detail in Note 12B. This discussion identifies specific issues,
      the status of the issues, accruals associated with issue resolutions and our
      associated exposures.




66


**Nuclear**




Nuclear
      generating units are regulated by the NRC. In the event of noncompliance, the
      NRC has the authority to impose fines, set license conditions, shut down a
      nuclear unit or take some combination of these actions, depending upon its
      assessment of the severity of the situation, until compliance is achieved.




Our
      nuclear units are periodically removed from service to accommodate normal
      refueling and maintenance outages, repairs and certain other modifications
      (See
      Note 12B).




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.




We
      have
      announced that we are pursuing development of combined license (COL)
      applications. Our announcement is not a commitment to build a nuclear plant.
      It
      is a necessary step to keep open the option of building a plant or plants.
      On
      January 23, 2006, we announced that PEC selected a site at the Shearon Harris
      Nuclear Plant (Harris) to evaluate for possible future nuclear expansion. We
      currently expect to file the application for the COL for PEC’s Harris site in
      2007. We have selected for PEC the Westinghouse Electric AP-1000 reactor design
      as the technology upon which to base the potential application submission.
      On
      December 12, 2006, we announced that PEF selected a site in Levy County, Fla.,
      to evaluate for possible future nuclear expansion, and PEF expects to file
      the
      application for the COL in 2008. We have not selected the reactor design
      technology upon which to base the PEF potential application submission. If
      we
      receive approval from the NRC and applicable state agencies, and if the
      decisions to build are made, construction activities could begin as early as
      2010, and new plants could be online in late 2016. The NRC estimates that it
      will take approximately three to four years to review and process the COL
      applications.




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. The extent and timing of the NRC’s application of the
      case is unclear at this time, and the impact, if any, on PEC’s pending Harris
      operating license renewal application or any future PEC or PEF operating
      licensing proceedings cannot be predicted at this time.




A
      new
      nuclear plant may be eligible for the federal production tax credits and risk
      insurance provided by the Energy Policy Act of 2005 (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 discussed
      above, in December 2006, the FPSC ordered new rules 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




67


requirements.




**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 11). 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 11.




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 oxide (NOx), SO 2 ,
      carbon
      dioxide (CO 2 )
      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. Estimated 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.




68


***Progress
      Energy***


**Air
                and Water Quality Estimated Required Environmental Expenditures***(in
                millions)*
            Estimated
                Timetable
            Total
                Estimated Expenditures
            Cumulative
                Spent through March 31, 2007NOx
                SIP Call
            2002-2007
            $345
                - $350
            $341Clean
                Smokestacks Act
            2002-2013
            1,100
                - 1,400
            666CAIR/CAMR/CAVR
            2005-2018
            1,100
                - 2,000
            59Total
                air quality
            
            2,545
                - 3,750
            1,066Clean
                Water Act Section 316(b)(a)
            
            -
            1North
                Carolina Groundwater Standard(b)
            
            -
            -Total
                water quality
            
            -
            1Total
                air and water quality
            
            $2,545
                - $3,750
            $1,067





***PEC***


**Air
                and Water Quality Estimated Required Environmental Expenditures***(in
                millions)*
            Estimated
                Timetable
            Total
                Estimated Expenditures
            Cumulative
                Spent through March 31, 2007NOx
                SIP Call
            2002-2007
            $345
                - $350
            $341Clean
                Smokestacks Act
            2002-2013
            1,100
                - 1,400
            666CAIR/CAMR/CAVR
            2005-2018
            200
                - 300
            2Total
                air quality
            
            1,645
                - 2,050
            1,009Clean
                Water Act Section 316(b)(a)
            
            -
            -North
                Carolina Groundwater Standard(b)
            
            -
            -Total
                water quality
            
            -
            -Total
                air and water quality
            
            $1,645
                - $2,050
            $1,009





***PEF***


**Air
                and Water Quality Estimated Required Environmental Expenditures***(in
                millions)*
            Estimated
                Timetable
            Total
                Estimated Expenditures
            Cumulative
                Spent through March 31, 2007CAIR/CAMR/CAVR
            2005-2018
            $900
                - $1,700
            $57Clean
                Water Act Section 316(b)(a)
            
            -
            1Total
                air and water quality
            
            $900
                - $1,700
            $58





(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
      related to an appeal of a decision issued by 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 there is an emissions
      increase.




69


On
      March
      17, 2006, the U.S. Court of Appeals for the District of Columbia Circuit (D.C.
      Circuit Court) 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. Circuit Court 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. Circuit Court’s 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. Circuit Court 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,
      South
      Carolina and Georgia, to further reduce NOx emissions. The NOx SIP Call is
      not
      applicable to Florida. Further technical analysis and rulemaking may result
      in
      requirements for additional controls at some units. 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 SO 2 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. 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. See further discussion about the Clean Smokestacks Act
      in
      Note 4A.




Two
      of
      PEC’s largest coal-fired generation plants (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 11B).




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 SO 2 emissions allowances that result from compliance with the collective NOx and
      SO 2 emissions limitations set in the Clean Smokestacks Act. The Clean Smokestacks
      Act also required the state to undertake a study of mercury and CO 2 emissions in North Carolina. The future regulatory interpretation,
      implementation or impact of the Clean Smokestacks Act cannot be
      predicted.




**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, Georgia and
      Florida, to reduce NOx and SO 2 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 SO 2 .




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. Circuit Court 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




70


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 SO 2 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 SO 2 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 by November 17, 2006, to adopt mercury rules implementing the
      CAMR
      that are subject to review and approval by the EPA. A number of states,
      including North Carolina, South Carolina and Florida, did not meet the deadline
      for submission to the EPA. The EPA has indicated it will defer action. The
      three
      states in which the Utilities operate formally proposed mercury regulations.
      North Carolina and Florida have submitted their state rules to the EPA. The
      North Carolina Environmental Management Commission adopted the North Carolina
      rule on November 9, 2006. North Carolina's rule adopts 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 SO 2 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.
      South Carolina’s rule is subject to final approval by the South Carolina
      legislature. On June 29, 2006, the Florida Environmental Regulation Commission
      adopted the Florida CAMR. The Florida rule adopts the EPA’s cap-and-trade
      approach with changes to the EPA’s mercury allowance allocations in the rule’s
      first phase. 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
      SO 2 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. Circuit Court 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 SO 2 from
      electric generating units in areas covered by CAIR.




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


71


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
      October 27, 2006, PEF filed supplemental testimony to inform the FPSC that
      estimated capital costs for the series of compliance alternatives are likely
      to
      increase by approximately 25 percent to 30 percent from the estimates filed
      in
      March 2006, 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. 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.




**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 SO 2 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. Circuit Court 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 U.S. Circuit
      Court of Appeals for the District of Columbia Circuit 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.




**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


72


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 March 20, 2007, the EPA directed the
        Regional Administrators to consider the July 2004 rule as suspended. No formal
        notice has been published in the Federal Register. 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.





**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 CO 2 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 to address global climate change that would regulate
      CO 2 and
      other greenhouse gases. Reductions in CO 2 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 voluntary action
      on
      this important issue as part of our commitment to environmental stewardship
      and
      responsible corporate citizenship.




In
      a
      decision issued July 15, 2005, the D.C. Circuit Court denied petitions for
      review filed by several states, cities and organizations seeking the regulation
      by the EPA of CO 2 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
      CO 2 emissions from new automobiles. The impact of this decision cannot be
      predicted.




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.




**New
      Accounting
      Standards**




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




73


***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 decreased $27 million for the three months
      ended March 31, 2007, when compared to the corresponding period in the prior
      year. The decrease in operating cash flow was primarily due to a $54 million
      decrease from the change in accounts receivable, principally driven by the
      timing of wholesale sales, and a $64 million decrease from payables, primarily
      related to the timing of settlements with affiliates. These impacts were largely
      offset by approximately $100 million in tax payments paid in the prior
      year.




Cash
      used
      in investing activities increased $24 million for the three months ended March
      31, 2007, when compared to the corresponding period in the prior year, primarily
      due to a $57 million increase in capital expenditures for utility property
      additions, primarily related to an increase in spending for compliance with
      the
      Clean Smokestacks Act, partially offset by a $24 million decrease in note
      receivable from affiliate.




**OFF-BALANCE
      SHEET ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS**




As
      of
      March 31, 2007, PEC’s off-balance sheet arrangements and contractual obligations
      have not changed materially from what was reported in the 2006 Form
      10-K.




**Market
      Risk a****nd 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 8 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
      of
      March 31, 2007, PEC’s contractual cash obligations and other commercial
      commitments have not changed materially from what was reported in the 2006
      Form
      10-K.




**O****THER
      MATTERS**




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




74


***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**




Cash
      provided by operating activities increased $96 million for the three months
      ended March 31, 2007, when compared to the corresponding period in the prior
      year. The increase was primarily due to higher coal inventory purchases in
      the
      prior year of $54 million, $47 million in net refunds of cash collateral
      previously paid to counterparties on derivative contracts, and $53 million
      related to lower income tax payments. These impacts were partially offset by
      a
      $46 million decrease in the recovery of fuel costs.




Cash
      used
      in investing activities increased $58 million for the three months ended March
      31, 2007, when compared to the corresponding period in the prior year. The
      increase in cash used in investing activities was primarily due to a $99 million
      increase in capital expenditures for utility property additions, primarily
      due
      to repowering the Bartow plant to more efficient natural gas-burning technology
      and steam production projects, partially offset by lower spending at the Hines
      Unit 4 facility; and a $17 million increase in nuclear fuel additions. These
      impacts were partially offset by a $55 million decrease in net purchases of
      short-term investments included in available-for-sale securities and other
      investments. Available-for-sale securities and other investments include
      marketable debt securities and investments held in nuclear decommissioning
      trusts.





See
      Progress Energy’s MD&A, “Liquidity and Capital Resources” for a discussion
      of PEF’s financing activities.





**OFF-BALANCE
      SHEET ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS**





As
      of
      March 31, 2007, PEF’s off-balance sheet arrangements and contractual obligations
      have not changed materially from what was reported in the 2006 Form
      10-K.




**Market
      Risk a****nd 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 8 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
      of
      March 31, 2007, PEF’s contractual cash obligations and other commercial
      commitments have not changed materially from what was reported in the 2006
      Form
      10-K.




**O****THER
      MATTERS**




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




75


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
      8).




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 March 31, 2007, has changed from December 31, 2006. The total
      notional amount of fixed rate long-term debt at March 31, 2007, was $7.830
      billion, with an average interest rate of 6.26% and fair market value of $8.144
      billion. The total notional amount of variable rate long-term debt at March
      31,
      2007, was $1.411 billion, with an average interest rate of 4.39% and fair market
      value of $1.411 billion.




In
      addition to our variable rate long-term debt, we typically have commercial
      paper
      and/or loans outstanding under our RCA facilities, which are also exposed to
      floating interest rates. At March 31, 2007, approximately 16.9 percent of
      consolidated debt, including interest rate swaps, was in floating rate mode
      compared to 15.8 percent at the end of 2006.




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 risk in the transaction is the cost of replacing the agreements at current
      market rates. We only enter into interest rate derivative agreements with banks
      with credit ratings of single A or better.




We
      use a
      number of models and methods to determine interest rate risk exposure and fair
      value of derivative positions. For reporting purposes, fair values and exposures
      of derivative positions are determined as of the end of the reporting period
      using the Bloomberg Financial Markets system.




76


In
      accordance with 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
      March
      31, 2007 and December 31, 2006, the Utilities had a combined $150 million
      notional and $100 million notional, respectively, 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 March 31, 2007 and December
      31, 2006.


Cash
                Flow Hedges (dollars in millions)
            Notional
                Amount
            Pay
            Receive(a)
            Fair
                Value
            Exposure(b)PEC**Risk
                hedged at March 31, 2007:****Anticipated
                10-year debt issue****(c)**
            **$50**
            **5.61%**
            **3-month
                LIBOR**
            **$(2)**
            **$(1)**Risk
                hedged at December 31, 2006:Anticipated
                10-year debt issue(c)
            $50
            5.61%
            3-month
                LIBOR
            $(1)
            $(1)PEF**Risk
                hedged at March 31, 2007:****Anticipated
                10-year debt issue****(c)**
            **$50**
            **5.61%**
            **3-month
                LIBOR**
            **$(2)**
            **$(1)****Anticipated
                10-year debt issue****(d)**
            **$50**
            **5.20%**
            **3-month
                LIBOR**
            **-**
            **(1)****Total**
            **$100**
            **5.40%**
            
            **$(2)**
            **$(2)**Risk
                hedged at December 31, 2006:Anticipated
                10-year debt issue(c)
            $50
            5.61%
            3-month
                LIBOR
            $(1)
            $(1)


(a)
            3-month
                LIBOR rate was 5.35% at March 31, 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 hedges mature on October 1, 2017, and require
                mandatory
                cash settlement on October 1, 2007.


(d)
            Anticipated
                10-year debt issue hedge matures on June 1, 2017, and requires mandatory
                cash settlement on June 1, 2007.





PEF
      entered into a $50 million forward starting swap on February 16, 2007, to
      mitigate exposure to interest rate risk in anticipation of future debt
      issuances.




77


**Fair
      Value Hedges**




At
      March
      31, 2007 and December 31, 2006, the Parent had $50 million notional of fixed
      rate debt swapped to floating rate debt. Under terms of these swap agreements,
      we will receive a fixed rate and pay a floating rate based on 3-month LIBOR.
      At
      March 31, 2007 and December 31, 2006, the Utilities had no open interest rate
      fair value hedges.


Fair
                Value Hedges*(dollars
                in millions)*Progress
                Energy
            Notional
                Amount
            Receive
            Pay(a)
            Fair
                Value
            Exposure(b)**Risk
                hedged at March 31, 2007****7.10%
                Notes due 3/1/2011**
            **$50**
            **4.65%**
            **3-month
                LIBOR**
            **$(1)**
            **$-**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 5.35% at March 31, 2007 and 5.36% as of December 31,
                2006.


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





**MARKETABLE
      SECURITIES PRICE RISK**




At
      March
      31, 2007 and December 31, 2006, the fair value of our nuclear decommissioning
      trust funds was $1.307 billion and $1.287 billion, respectively, including
      $749
      million and $735 million, respectively, for PEC and $558 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 March 31, 2007 and December 31, 2006,
      the
      fair value of CVOs was $31 million and $32 million, respectively. A hypothetical
      10 percent decrease in the March 31, 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
      the “Other Matters” section of Item 2.




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.




As
      discussed in Note 3, on March 9, 2007, we entered into two separate agreements
      to dispose of substantially all of PVI’s remaining CCO physical and commercial
      assets and on October 2, 2006, we sold Gas. Due to these divestiture plans,
      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. This increased
      our
      exposure to


78


potential
      earnings impacts in the near term from changes in commodity market prices.




At
      March
      31, 2007 and December 31, 2006, derivative assets of $178 million and $107
      million, respectively, were included in assets of discontinued operations and
      derivative liabilities of $10 million and $31 million, respectively, were
      included in liabilities of discontinued operations on the Consolidated Balance
      Sheets. For the three months ending March 31, 2007, gains from derivative
      instruments of $59 million were included in discontinued operations, net of
      tax
      on the Consolidated Statement of Income. For the three months ending March
      31,
      2006, net gains and losses from derivative instruments of discontinued
      operations were not material. For the three months ending March 31, 2007 and
      2006, there were no reclassifications to earnings due to discontinuance of
      the
      related cash flow hedges.




We
      perform sensitivity analyses to estimate our exposure to the market risk of
      our
      derivative commodity instruments, which are not eligible for recovery from
      ratepayers. As described above, at March 31, 2007, a portion of these derivative
      commodity instruments are included in discontinued operations. At December
      31,
      2006, all of these derivative commodity instruments are included in discontinued
      operations. 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. A decrease of 10 percent in the market prices of energy
      commodities from their March 31, 2007, levels would decrease after-tax earnings
      by approximately $87 million, including a $79 million decrease in after-tax
      earnings of 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 physical purchases of natural gas and power 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 of discontinued operations
      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
      8 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.




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. PEC and PEF did not have material
      outstanding positions in such contracts at March 31, 2007 and December 31,
      2006,
      other than those receiving regulatory accounting treatment, as discussed
      below.




At
      March
      31, 2007, the fair value of PEC’s derivative instruments was recorded as a $4
      million long-term derivative asset position included in other assets and
      deferred debits on the Consolidated Balance Sheet. At December 31, 2006, PEC
      did
      not have material outstanding positions in such contracts.





At
      March
      31, 2007, the fair value of PEF’s derivative instruments was recorded as a $2
      million short-term derivative asset position included in derivative assets,
      a
      $17 million long-term derivative asset position included in


79


other
      assets and deferred debits, a $31 million short-term derivative liability
      position included in other current liabilities, and an $11 million long-term
      derivative liability position included in other liabilities and deferred credits
      on the Consolidated 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 other current liabilities and a $36
      million long-term derivative liability position included in other liabilities
      and deferred credits on the Consolidated Balance Sheet.





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
      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 3H, 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. At March 31, 2007, the
      fair
      value of these contracts was recorded as a $110 million short-term derivative
      asset position, including $37 million at Ceredo. The fair value of these
      contracts was included in derivative assets on the Consolidated Balance Sheet.
      During the three months ended March 31, 2007, we recorded net pre-tax gains
      of
      $45 million in diversified business revenues related to these contracts. We
      anticipate that future mark-to-market changes on the Ceredo portion of the
      derivatives contracts will have no net earnings impact.




**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 March 31, 2007, we and the Utilities did not have material
      outstanding positions in such contracts.





***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.




***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).




80


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 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 March 31, 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 March 31, 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 March 31, 2007, that has materially affected, or is reasonably
      likely to materially affect, its internal control over financial
      reporting.




81


PART
      II.  OTHER
      INFORMATION





Item
      1.  Legal
      Proceedings





Legal
      aspects of certain matters are set forth in PART I, Item 1 (See Note
      12B).








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. There have been no
      material changes to the risk factors as set forth in the 2006 Form
      10-K.








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





RESTRICTED
      STOCK AWARDS





(a)
            Securities
                Delivered.On
                March 12, 2007, 7,000 restricted shares of our common stock were
                granted
                to a key employee pursuant to the terms of the Progress Energy 2002
                Equity Incentive Plan (EIP), which was approved by the Progress Energy’s
                shareholders on May 8, 2002. Section 9 of the EIP provides for the
                granting of Restricted Stock by the Organization and Compensation
                Committee of the Board of Directors, (the Committee) to key employees,
                including our Affiliates or any successor, and to our outside directors.
                The shares of common stock delivered pursuant to the EIP were acquired
                in
                market transactions directly for the accounts of the recipient and
                do not
                represent 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. The shares were delivered to a certain key employee.
                The
                EIP defines "key employee" as an officer or other employee of Progress
                Energy who is selected for participation in the EIP.





(c)
            Consideration.The shares of our common stock were delivered to provide an incentive
                to
                the employee recipient to exert her utmost efforts on Progress Energy’s
                behalf and thus enhance our performance while aligning the employee's
                interest with those of our shareholders.





(d)
            Exemption
                from Registration Claimed.The common shares described in this Item were delivered on the basis
                of an
                exemption from registration under Section 4(2) of the Securities
                Act of
                1933. Receipt of the shares of our common stock required no investment
                decision on the part of the
                recipient.





PERFORMANCE
      SHARE SUB-PLAN AWARD PAYOUT





(a)
            Securities
                Delivered.On
                January 9, 2007, 19 shares of our common stock were delivered to
                a former
                employee pursuant to the terms of the 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.





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(c)
            Consideration.The performance share awards were granted to provide an incentive
                  to
                  the recipient to exert his utmost efforts on Progress Energy’s behalf
                  and thus enhance our performance while aligning the recipient's
                  interest
                  with those of our shareholders. 
 (d)
            Exemption
                from Registration Claimed.The common shares described in this Item were delivered pursuant
                to a
                broad-based involuntary, non-contributory employee benefit plan,
                and thus
                did not involve an offer to sell or sale of securities within the
                meaning
                of Section 2(3) of the Securities Act of 1933. Receipt of the shares
                of
                our common stock required no investment decision on the part of the
                recipient.


ISSUER
      PURCHASES OF EQUITY SECURITIES FOR FIRST QUARTER OF 2007




**Period**
            **(a)**
              **Total
                Number**
              **of
                Shares**
              **(or
                Units)**
              **Purchased
                (1)**
            **(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)**January
                1 - January 31
            31,807
                (2)
            $47.40
            N/A
            N/AFebruary
                1 - February 28
            -
            -
            N/A
            N/AMarch
                1 - March 31
            36,000
                (3)
            $48.56
            N/A
            N/ATotal
            67,807
            $48.02
            N/A
            N/A






(1)
            As
                of March 31, 2007, Progress Energy does not have any publicly announced
                plans or programs to purchase shares of its common
                stock.


(2)
            The
                plan administrator purchased 31,807 shares of our common stock at
                an
                average price of $47.40 in open-market transactions to meet share
                delivery
                obligations under the 401(k).


(3)
            The
                plan administrator purchased 29,000 shares of our common stock at
                an
                average price of $48.32 in open market transactions to meet share
                delivery
                obligations under our 401(k). Open market transactions also were
                executed
                to purchase 7,000 shares of our common stock at an average price
                of $49.54
                in connection with a restricted stock award that was granted to a
                certain
                employee pursuant to the terms of our Equity Incentive
                Plan.








Item
      5 .  Other
      Information





Effective
      May 8, 2007, each of Robert B. McGehee, William D. Johnson, Peter M. Scott
      III,
      Clayton S. Hinnant, Fredrick N. Day IV and John R. McArthur entered into
      Employment Agreements (the “Employment Agreements” and each an “Employment
      Agreement”) with our subsidiaries for which they are employed respectively. The
      Employment Agreements replace the previous employment agreements in effect
      for
      each of these officers, except that, (i) with respect to Mr. Scott, the
      Amendment to Employment Agreement dated August 5, 2005 remains in force in
      accordance with its terms and (ii) with respect to Mr. Hinnant, the Selected
      Executives Supplemental Deferred Compensation Program Agreement remains in
      force
      in accordance with its terms, both of which have been previously filed with
      the
      SEC.




The
      initial term of each Employment Agreement expires on December 31, 2009, with
      the
      term automatically extending by an additional year on January 1 of each year.
      We
      can choose not to extend an Employment Agreement upon providing notice of such
      nonrenewal to the applicable officer at least 60 days prior to the automatic
      extension date. Except for the application of previously granted years of
      service credit to our post-employment health and welfare benefit plans as
      discussed below, the Employment Agreements do not effect the compensation,
      benefits or incentive targets payable to the applicable officers, and such
      programs remain as previously disclosed in the our Proxy Statement filed on
      March 30, 2007.




With
      respect to Messrs. McGehee, Johnson and Scott, the Employment Agreements specify
      that the years of service


83


credit
      we
      previously granted to them for purposes of determining eligibility and benefits
      in the Supplemental Senior Executive Retirement Plan will also be applicable
      for
      purposes of determining eligibility and benefits in our post-employment health
      and welfare benefit plans.




Each
      Employment Agreement provides that if the applicable officer is terminated
      without cause or is constructively terminated (as defined in Paragraph 8(a)(i)
      of the agreement), then the officer will receive (i) severance equal to 2.99
      times the officer’s then-current base salary and (ii) reimbursement for the
      costs of continued coverage under certain of our health and welfare benefit
      plans for a period of up to 18 months.




The
      Employment Agreements each contain restrictive covenants imposing
      non-competition obligations, restricting solicitation of employees and
      protecting our confidential information and trade secrets for specified periods
      if the applicable officer is terminated without cause or otherwise becomes
      eligible for the benefits available under the agreement.




The
      above
      description of the Employment Agreements is qualified by reference to the Form
      of Executive Employment Agreement, which is attached hereto as Exhibit 10 and
      is
      incorporated by reference in its entirety.








Item
      6.  Exhibits





(a)
            Exhibits




ExhibitNumber
            Description
            Progress
              Energy
            PEC
            PEF10
            Form
                of Executive Employment Agreement
            X
            X
            X31(a)
            302
                Certifications of Chief Executive Officer
            X31(b)
            302
                Certifications of Chief Financial Officer
            X31(c)
            302
                Certifications of Chief Executive Officer
            
            X31(d)
            302
                Certifications of Chief Financial Officer
            
            X31(e)
            302
                Certifications of Chief Executive Officer
            
            
            X31(f)
            302
                Certifications of Chief Financial Officer
            
            
            X32(a)
            906
                Certifications of Chief Executive Officer
            X32(b)
            906
                Certifications of Chief Financial Officer
            X32(c)
            906
                Certifications of Chief Executive Officer
            
            X32(d)
            906
                Certifications of Chief Financial Officer
            
            X32(e)
            906
                Certifications of Chief Executive Officer
            
            
            X32(f)
            906
                Certifications of Chief Financial Officer
            
            
            X





84





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 COMPANYFLORIDA
                POWER CORPORATIONDate:
                May 8, 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 CompanyFlorida
                Power Corporation




85