UNITED
STATES


SECURITIES
AND EXCHANGE COMMISSION


Washington,
D.C. 20549





FORM
10-Q





xQUARTERLY
REPORT PURSUANT TO SECTION 13 OR 15(d)


OF
THE SECURITIES EXCHANGE ACT OF 1934





For the
quarterly period ended March 31, 2009





OR





oTRANSITION
REPORT PURSUANT TO SECTION 13 OR


15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934





For the
transition period
from                      to                    .








Commission
      File Number
              Exact
      name of registrants as specified in their charters, states of
      incorporation, addresses of principal executive offices,
                and
      telephone numbers
              I.R.S.
      Employer Identification Numberpgn logo1-15929
              Progress
      Energy, Inc.
                410
      South Wilmington Street
                Raleigh,
      North Carolina 27601-1748
                Telephone:   (919)
      546-6111
                State
      of Incorporation: North Carolina
              56-21554811-3382
              Carolina
      Power & Light Company
                d/b/a
      Progress Energy Carolinas, Inc.
                410
      South Wilmington Street
                Raleigh,
      North Carolina  27601-1748
                Telephone:   (919)
      546-6111
                State
      of Incorporation: North Carolina
              56-01654651-3274
              Florida
      Power Corporation
                d/b/a
      Progress Energy Florida, Inc.
                299
      First Avenue North
                St.
      Petersburg, Florida  33701
                Telephone:   (727)
      820-5151
                State
      of Incorporation: Florida
              59-0247770





NONE


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





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





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









Indicate
by check mark whether each registrant has submitted electronically and posted to
its corporate Web site, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding
12 months (or for such shorter period that the registrants were required to
submit and post such files).





Progress
      Energy
            Yes
            o
            No
            oPEC
            Yes
            o
            No
            oPEF
            Yes
            o
            No
            o





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





Progress
      Energy
            Large
      accelerated filer
            x
            Accelerated
      filer
            oNon-accelerated
      filer
            o
            Smaller
      reporting company
            oPEC
            Large
      accelerated filer
            o
            Accelerated
      filer
            oNon-accelerated
      filer
            x
            Smaller
      reporting company
            oPEF
            Large
      accelerated filer
            o
            Accelerated
      filer
            oNon-accelerated
      filer
            x
            Smaller
      reporting company
            o





Indicate
by check mark whether each registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act).





Progress
      Energy
            Yes
            o
            No
            xPEC
            Yes
            o
            No
            xPEF
            Yes
            o
            No
            x





At May 4,
2009, each registrant had the following shares of common stock
outstanding:





Registrant
                        Description
                        SharesProgress
      Energy
                        Common
      Stock (Without Par Value)
                        279,038,627PEC
                        Common
      Stock (Without Par Value)
                        159,608,055 (all
      of which were held directly by Progress Energy, Inc.)PEF
                        Common
      Stock (Without Par Value)
                        100
      (all of which were held indirectly by Progress Energy,
      Inc.)





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





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


2





TABLE
      OF CONTENTSGLOSSARY OF
      TERMSSAFE HARBOR FOR
      FORWARD-LOOKING STATEMENTSPART
      I.  FINANCIAL INFORMATIONITEM
      1.
                  FINANCIAL STATEMENTSUnaudited
      Condensed Interim Financial Statements:Progress Energy, Inc. (Progress
      Energy)Unaudited
      CondensedConsolidated Statements of
      IncomeUnauditedCondensedConsolidated Balance
      SheetsUnauditedCondensedConsolidated Statements of
      Cash FlowsCarolina Power & Light Company d/b/a Progress
      Energy Carolinas, Inc. (PEC)UnauditedCondensedConsolidated Statements of
      IncomeUnauditedCondensedConsolidated Balance
      SheetsUnauditedCondensedConsolidated Statements of
      Cash FlowsFlorida Power Corporation d/b/a Progress Energy
      Florida, Inc. (PEF)UnauditedCondensedStatements of
      IncomeUnauditedCondensedBalance
      SheetsUnauditedCondensedStatements of Cash
      FlowsCombined Notes to UnauditedCondensedInterim Financial Statements for Progress Energy,
      Inc., Carolina Power & Light Company d/b/a Progress Energy Carolinas,
      Inc. and Florida Power Corporation d/b/a Progress Energy Florida,
      Inc.ITEM
      2.
                  MANAGEMENT’S DISCUSSION AND
      ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
      OPERATIONSITEM
      3.
                  QUANTITATIVE AND
      QUALITATIVE DISCLOSURES ABOUT MARKET RISKITEM
      4.
                  CONTROLS AND
      PROCEDURESITEM
      4T.
                  CONTROLS AND
      PROCEDURESPART
      II.  OTHER INFORMATIONITEM
      1.
                  LEGAL
      PROCEEDINGSITEM
      1A.
                  RISK
      FACTORSITEM
      2.
                  UNREGISTERED SALES OF
      EQUITY SECURITIES AND USE OF PROCEEDSITEM
      6.
                  EXHIBITSSIGNATURES





3





GLOSSARY OF TERMS





We use
the words “Progress Energy,” “we,” “us” or “our” with respect to certain
information to indicate that such information relates to Progress Energy, Inc.
and its subsidiaries on a consolidated basis. When appropriate, the parent
holding company or the subsidiaries of Progress Energy are specifically
identified on an unconsolidated basis as we discuss their various business
activities.




The
following abbreviations or acronyms are used by the Progress
Registrants:




TERM
                  DEFINITION2008
      Form 10-K
                  Progress
      Registrants’ annual report on Form 10-K for the fiscal year ended December
      31, 2008401(k)
                  Progress
      Energy 401(k) Savings & Stock Ownership PlanAFUDC
                  Allowance
      for funds used during constructionARO
                  Asset
      retirement obligationAsset
      Purchase Agreement
                  Agreement
      by and among Global, Earthco and certain affiliates, and the Progress
      Affiliates as amended on August 23, 2000Audit
      Committee
                  Audit
      and Corporate Performance Committee of Progress Energy’s board of
      directorsBART
                  Best
      Available Retrofit TechnologyBroad
      River
                  Broad
      River LLC’s Broad River FacilityBrunswick
                  PEC’s
      Brunswick Nuclear PlantBtu
                  British
      thermal unitCAIR
                  Clean
      Air Interstate RuleCAMR
                  Clean
      Air Mercury RuleCAVR
                  Clean
      Air Visibility RuleCCO
                  Competitive
      Commercial OperationsCERCLA
      or Superfund
                  Comprehensive
      Environmental Response, Compensation and Liability Act of 1980, as
      amendedCeredo
                  Ceredo
      Synfuel LLCClean
      Smokestacks Act
                  North
      Carolina Clean Smokestacks Act, enacted in June 2002Coal
      Mining
                  Two
      Progress Fuels subsidiaries engaged in the coal mining
      businessthe
      Code
                  Internal
      Revenue CodeCO2
                  Carbon
      dioxideCOL
                  Combined
      licenseColona
                  Colona
      Synfuel Limited Partnership, LLLPCorporate
      and Other
                  Corporate
      and Other segment primarily includes the Parent, Progress Energy Service
      Company and miscellaneous other nonregulated businessesCR1
      and CR2
                  PEF’s
      Crystal River Units No. 1 and 2 coal-fired steam
  turbinesCR3
                  PEF’s
      Crystal River Unit No. 3 Nuclear PlantCR4
      and CR5
                  PEF’s
      Crystal River Units No. 4 and 5 coal-fired steam
  turbinesCVO
                  Contingent
      value obligationD.C.
      Court of Appeals
                  U.S.
      Court of Appeals for the District of Columbia CircuitDeSoto
                  DeSoto
      County Generating Co., LLCDIG
      Issue C20
                  FASB
      Derivatives Implementation Group Issue C20, “Interpretation of the Meaning
      of Not Clearly and Closely Related in Paragraph 10(b) regarding Contracts
      with a Price Adjustment Feature”Dixie
      Fuels
                  Dixie
      Fuels LimitedDOE
                  United
      States Department of EnergyDSM
                  Demand-side
      managementEarthco
                  Four
      coal-based solid synthetic fuels limited liability companies of which
      three were wholly ownedECCR
                  Energy
      Conservation Cost Recovery ClauseECRC
                  Environmental
      Cost Recovery ClauseEIP
                  Equity
      Incentive PlanEPACT
                  Energy
      Policy Act of 2005EPC
                  Engineering,
      procurement and
construction
 4
 ERO
                Electric
      reliability organizationESOP
                Employee
      Stock Ownership PlanFASB
                Financial
      Accounting Standards BoardFDEP
                Florida
      Department of Environmental ProtectionFERC
                Federal
      Energy Regulatory CommissionFGT
                Florida
      Gas Transmission Company, LLCFIN
      45
                FASB
      Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements
      for Guarantees, Including Indirect Guarantees of Indebtedness of
      Others”FIN
      46R
                FASB
      Interpretation No. 46R, “Consolidation of Variable Interest Entities – an
      Interpretation of ARB No. 51”FIN
      47
                FASB
      Interpretation No. 47, “Accounting for Conditional Asset Retirement
      Obligations – an Interpretation of FASB Statement No.
  143”FIN
      48
                FASB
      Interpretation No. 48, “Accounting for Uncertainty in Income
      Taxes”the
      Florida Global Case
                U.S.
      Global, LLC v. Progress Energy, Inc. et alFlorida
      Progress
                Florida
      Progress CorporationFlorida
      RPS
                Florida
      renewable portfolio standardFPSC
                Florida
      Public Service CommissionFRCC
                Florida
      Reliability Coordinating CouncilFSP
                FASB
      Staff PositionFSP
      EITF 03-6-1
                FASB
      Staff Position EITF 03-6-1, “Determining Whether Instruments Granted in
      Share-Based Payment Transactions Are Participating
    Securities”FSP
      FAS 115-2
                FASB
      Staff Position FAS 115-2 and FAS 124-2, “Recognition and Presentation of
      Other-Than-Temporary Impairments”FSP
      FAS 132R-1
                FASB
      Staff Position FAS 132(R)-1, “Employers’ Disclosures about Post Retirement
      Benefit Plan Assets”FSP
      FAS 157-2
                FASB
      Staff Position FAS 157-2, “Effective Date of FASB Statement No.
      157”Funding
      Corp.
                Florida
      Progress Funding Corporation, a wholly owned subsidiary of Florida
      ProgressGAAP
                Accounting
      principles generally accepted in the United States of
    AmericaGas
                Natural
      gas drilling and production businessthe
      Georgia Contracts
                Full-requirements
      contracts with 16 Georgia electric membership cooperatives formerly
      serviced by CCOGeorgia
      Operations
                Former
      reporting unit consisting of the Effingham, Monroe, Walton and Washington
      nonregulated generation plants in service and the Georgia
      ContractsGlobal
                U.S.
      Global, LLCGridSouth
                GridSouth
      Transco, LLCHarris
                PEC’s
      Shearon Harris Nuclear PlantkV
                KilovoltkVA
                Kilovolt-amperekWh
                Kilowatt-hoursLevy
                Proposed
      nuclear plant in Levy County, FloridaLIBOR
                London
      Inter Bank Offering RateMACT
                Maximum
      achievable control technologyMD&A
                Management’s
      Discussion and Analysis of Financial Condition and Results of Operations
      contained in Part I, Item 2 of this Form 10-QMedicare
      Act
                Medicare
      Prescription Drug, Improvement and Modernization Act of
    2003MGP
                Manufactured
      gas plantMW
                MegawattsMWh
                Megawatt-hoursMoody’s
                Moody’s
      Investors Service, Inc.NAAQS
                National
      Ambient Air Quality StandardsNC
      REPS
                North
      Carolina Renewable Energy and Energy Efficiency Portfolio
      StandardNCUC
                North
      Carolina Utilities CommissionNEIL
                Nuclear
      Electric Insurance LimitedNERC
                North
      American Electric Reliability CorporationNorth
      Carolina Global Case
                Progress
      Synfuel Holdings, Inc. et al. v. U.S. Global,
  LLC
  5
  the
      Notes Guarantee
                Florida
      Progress’ full and unconditional guarantee of the Subordinated
      NotesNOx
                Nitrogen
      OxidesNOx
      SIP Call
                EPA
      rule which requires 22 states including North Carolina, South Carolina and
      Georgia (but excluding Florida) to further reduce emissions of nitrogen
      oxidesNSR
                New
      Source Review requirements by the EPANRC
                United
      States Nuclear Regulatory CommissionO&M
                Operation
      and maintenance expenseOATT
                Open
      Access Transmission TariffOCI
                Other
      comprehensive incomeOPC
                Florida’s
      Office of Public CounselOPEB
                Postretirement
      benefits other than pensionsthe
      Parent
                Progress
      Energy, Inc. holding company on an unconsolidated basisPEC
                Carolina
      Power & Light Company d/b/a Progress Energy Carolinas,
      Inc.PEF
                Florida
      Power Corporation d/b/a Progress Energy Florida, Inc.PESC
                Progress
      Energy Service Company, LLCPower
      Agency
                North
      Carolina Eastern Municipal Power AgencyPreferred
      Securities
                7.10%
      Cumulative Quarterly Income Preferred Securities due 2039, Series A issued
      by the TrustPreferred
      Securities Guarantee
                Florida
      Progress’ guarantee of all distributions related to the Preferred
      SecuritiesProgress
      Affiliates
                Five
      affiliated coal-based solid synthetic fuels facilitiesProgress
      Energy
                Progress
      Energy, Inc. and subsidiaries on a consolidated basisProgress
      Registrants
                The
      reporting registrants within the Progress Energy consolidated group.
      Collectively, Progress Energy, Inc., PEC and PEFProgress
      Fuels
                Progress
      Fuels Corporation, formerly Electric Fuels CorporationPRP
                Potentially
      responsible party, as defined in CERCLAPSSP
                Performance
      Share Sub-PlanPUHCA
      1935
                Public
      Utility Holding Company Act of 1935, as amendedPUHCA
      2005
                Public
      Utility Holding Company Act of 2005PVI
                Progress
      Energy Ventures, Inc., formerly referred to as Progress Ventures,
      Inc.QF
                Qualifying
      facilityRCA
                Revolving
      credit agreementReagents
                Commodities
      such as ammonia and limestone used in emissions control
      technologiesREC
                Renewable
      energy certificatesRockport
                Indiana
      Michigan Power Company’s Rockport Unit No. 2Robinson
                PEC’s
      Robinson Nuclear PlantRSU
                Restricted
      stock unitRTO
                Regional
      transmission organizationSCPSC
                Public
      Service Commission of South CarolinaSection
      29
                Section
      29 of the CodeSection
      29/45K
                General
      business tax credits earned after December 31, 2005 for synthetic fuels
      production in accordance with Section 29Section
      316(b)
                Section
      316(b) of the Clean Water Act(See
      Note/s “#”)
                For
      all sections, this is a cross-reference to the Combined Notes to the
      Unaudited Condensed Interim Financial Statements contained in PART I, Item
      1 of this Form 10-QSERC
                SERC
      Reliability CorporationS&P
                Standard
      & Poor’s Rating ServicesSFAS
      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”
  6
  SFAS
      No. 123R
                    Statement
      of Financial Accounting Standards No. 123R, “Share-Based
      Payment”SFAS
      No. 133
                    Statement
      of Financial Accounting Standards No. 133, “Accounting for Derivative
      Instruments and Hedging Activities”SFAS
      No. 141R
                    Statement
      of Financial Accounting Standards No. 141R, “Business
      Combinations”SFAS
      No. 142
                    Statement
      of Financial Accounting Standards No. 142, “Goodwill and Other Intangible
      Assets”SFAS
      No. 143
                    Statement
      of Financial Accounting Standards No. 143, “Accounting for Asset
      Retirement Obligations”SFAS
      No. 144
                    Statement
      of Financial Accounting Standards No. 144, “Accounting for the Impairment
      or Disposal of Long-Lived Assets”SFAS
      No. 157
                    Statement
      of Financial Accounting Standards No. 157, “Fair Value
      Measurements”SFAS
      No. 158
                    Statement
      of Financial Accounting Standards No. 158, “Employers’ Accounting for
      Defined Benefit Pension and Other Postretirement Plans”SFAS
      No. 159
                    Statement
      of Financial Accounting Standards No. 159, “The Fair Value Option for
      Financial Assets and Financial Liabilities – Including an amendment of
      FASB Statement No. 115”SFAS
      No. 160
                    Statement
      of Financial Accounting Standards No. 160, “Noncontrolling Interests in
      Consolidated Financial Statements, an amendment of ARB No.
    51”SFAS
      No. 161
                    Statement
      of Financial Accounting Standards No. 161, “Disclosures About Derivative
      Instruments and Hedging Activities – an amendment of FASB Statement No.
      133”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 AgreementTerminals
                    Coal
      terminals and docks in West Virginia and Kentuckythe
      Trust
                    FPC
      Capital Ithe
      Utilities
                    Collectively,
      PEC and PEFVIE
                    Variable
      interest entityWard
                    Ward
      Transformer site located in Raleigh, N.C.Ward
      OU1
                    Operable
      unit for stream segments downstream from the Ward siteWard
      OU2
                    Operable
      unit for further investigation at the Ward facility and certain adjacent
      areas
  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 tax credits, the
effects of new environmental regulations, meeting anticipated demand in our
regulated service territories, potential nuclear construction and changes in the
regulatory environment.




Examples
of factors that you should consider with respect to any forward-looking
statements made throughout this document include, but are not limited to, the
following: the impact of fluid and complex laws and regulations, including those
relating to the environment and the Energy Policy Act of 2005 (EPACT); the
ability to meet the anticipated future need for additional baseload generation
and associated transmission facilities in our regulated service territories and
the accompanying regulatory and financial risks; the financial resources and
capital needed to comply with environmental laws and renewable energy portfolio
standards and our ability to recover related eligible costs under cost-recovery
clauses or base rates; our ability to meet current and future renewable energy
requirements; the inherent risks associated with the operation and potential
construction of nuclear facilities, including environmental, health, regulatory
and financial risks; the impact on our facilities and businesses from a
terrorist attack; weather and drought conditions that directly influence the
production, delivery and demand for electricity; recurring seasonal fluctuations
in demand for electricity; the ability to recover in a timely manner, if at all,
costs associated with future significant weather events through the regulatory
process; economic fluctuations and the corresponding impact on our customers,
including downturns in the housing and consumer credit markets; fluctuations in
the price of energy commodities and purchased power and our ability to recover
such costs through the regulatory process; the Progress Registrants’ ability to
control costs, including operations and maintenance expense (O&M) and large
construction projects; the ability of our subsidiaries to pay upstream dividends
or distributions to Progress Energy, Inc. holding company (the Parent); the
duration and severity of the current financial market distress that began in the
third quarter of 2008; the ability to successfully access capital markets on
favorable terms; the stability of commercial credit markets and our access to
short- and long-term credit; the impact that increases in leverage may have on
each of the Progress Registrants; the Progress Registrants’ ability to maintain
their current credit ratings and the impact on the Progress Registrants’
financial condition and ability to meet their cash and other financial
obligations in the event their credit ratings are downgraded; our ability to
fully utilize tax credits generated from the previous production and sale of
qualifying synthetic fuels under Internal Revenue Code Section 29/45K (Section
29/45K); the investment performance of our nuclear decommissioning trust funds;
the investment performance of the assets of our pension and benefit plans and
resulting impact on future funding requirements; the impact of goodwill
impairments; the outcome of any ongoing or future litigation or similar disputes
and the impact of any such outcome or related settlements; and unanticipated
changes in operating expenses and capital expenditures. Many of these risks
similarly impact our nonreporting subsidiaries.




These and
other risk factors are detailed from time to time in the Progress Registrants’
filings with the SEC. Many, but not all, of the factors that may impact actual
results are discussed in the Risk Factors section in the Progress Registrants’
annual report on Form 10-K for the fiscal year ended December 31, 2008 (2008
Form 10-K), which was filed with the SEC on March 2, 2009, and is updated for
material changes, if any, in this Form 10-Q and in our other SEC filings. All
such factors are difficult to predict, contain uncertainties that may materially
affect actual results and may be beyond our control. New factors emerge from
time to time, and it is not possible for management to predict all such factors,
nor can management assess the effect of each such factor on the Progress
Registrants.




8





PART
I.  FINANCIAL INFORMATION





ITEM
1.                      FINANCIAL STATEMENTS




PROGRESS ENERGY, INC.


UNAUDITED
CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS


March
31, 2009





UNAUDITED
      CONDENSED CONSOLIDATED STATEMENTS of INCOME(in
      millions except per share data)Three
      months ended March 31
                                      
                                      2009
                                      
                                      
                                      2008Operating
      revenues
                                      
                                      $
                                      2,442
                                      
                                      
                                      $
                                      2,066Operating
      expensesFuel
      used in electric generation
                                      
                                      
                                      954
                                      
                                      
                                      
                                      697Purchased
      power
                                      
                                      
                                      217
                                      
                                      
                                      
                                      232Operation
      and maintenance
                                      
                                      
                                      453
                                      
                                      
                                      
                                      443Depreciation,
      amortization and accretion
                                      
                                      
                                      280
                                      
                                      
                                      
                                      206Taxes
      other than on income
                                      
                                      
                                      143
                                      
                                      
                                      
                                      121Other
                                      
                                      
                                      2
                                      
                                      
                                      
                                      2Total
      operating expenses
                                      
                                      
                                      2,049
                                      
                                      
                                      
                                      1,701Operating
      income
                                      
                                      
                                      393
                                      
                                      
                                      
                                      365Other
      income (expense)Interest
      income
                                      
                                      
                                      4
                                      
                                      
                                      
                                      7Allowance
      for equity funds used during construction
                                      
                                      
                                      39
                                      
                                      
                                      
                                      23Other,
      net
                                      
                                      
                                      (1
                                      )
                                      
                                      
                                      (5
                                      )Total
      other income, net
                                      
                                      
                                      42
                                      
                                      
                                      
                                      25Interest
      chargesInterest
      charges
                                      
                                      
                                      179
                                      
                                      
                                      
                                      161Allowance
      for borrowed funds used during construction
                                      
                                      
                                      (12
                                      )
                                      
                                      
                                      (8
                                      )Total
      interest charges, net
                                      
                                      
                                      167
                                      
                                      
                                      
                                      153Income
      from continuing operations before income tax
                                      
                                      
                                      268
                                      
                                      
                                      
                                      237Income
      tax expense
                                      
                                      
                                      85
                                      
                                      
                                      
                                      84Income
      from continuing operations
                                      
                                      
                                      183
                                      
                                      
                                      
                                      153Discontinued
      operations, net of tax
                                      
                                      
                                      –
                                      
                                      
                                      
                                      61Net
      income
                                      
                                      
                                      183
                                      
                                      
                                      
                                      214Net
      income attributable to noncontrolling interests, net of
tax
                                      
                                      
                                      (1
                                      )
                                      
                                      
                                      (5
                                      )Net
      income attributable to controlling interests
                                      
                                      $
                                      182
                                      
                                      
                                      $
                                      209Average
      common shares outstanding – basic
                                      
                                      
                                      277
                                      
                                      
                                      
                                      260Basic
      and diluted earnings per common shareIncome
      from continuing operations attributable to controlling interests, net of
      tax
                                      
                                      $
                                      0.66
                                      
                                      
                                      $
                                      0.57Discontinued
      operations attributable to controlling interests, net of
    tax
                                      
                                      
                                      –
                                      
                                      
                                      
                                      0.23Net
      income attributable to controlling interests
                                      
                                      $
                                      0.66
                                      
                                      
                                      $
                                      0.80Dividends
      declared per common share
                                      
                                      $
                                      0.620
                                      
                                      
                                      $
                                      0.615Amounts
      attributable to controlling interestsIncome
      from continuing operations attributable to controlling interests, net of
      tax
                                      
                                      $
                                      182
                                      
                                      
                                      $
                                      149Discontinued
      operations attributable to controlling interests, net of
    tax
                                      
                                      
                                      –
                                      
                                      
                                      
                                      60Net
      income attributable to controlling interests
                                      
                                      $
                                      182
                                      
                                      
                                      $
                                      209See
      Notes to Progress Energy, Inc. Unaudited Condensed Consolidated Interim
      Financial Statements.


9




PROGRESS ENERGY, INC.UNAUDITED
      CONDENSED CONSOLIDATED BALANCE SHEETS(in
      millions)
                            
                            March
      31, 2009
                            
                            
                            December
      31, 2008ASSETSUtility
      plantUtility
      plant in service
                            
                            $
                            26,600
                            
                            
                            $
                            26,326Accumulated
      depreciation
                            
                            
                            (11,441
                            )
                            
                            
                            (11,298
                            )Utility
      plant in service, net
                            
                            
                            15,159
                            
                            
                            
                            15,028Held
      for future use
                            
                            
                            38
                            
                            
                            
                            38Construction
      work in progress
                            
                            
                            2,973
                            
                            
                            
                            2,745Nuclear
      fuel, net of amortization
                            
                            
                            466
                            
                            
                            
                            482Total
      utility plant, net
                            
                            
                            18,636
                            
                            
                            
                            18,293Current
      assetsCash
      and cash equivalents
                            
                            
                            632
                            
                            
                            
                            180Receivables,
      net
                            
                            
                            844
                            
                            
                            
                            867Inventory
                            
                            
                            1,300
                            
                            
                            
                            1,239Regulatory
      assets
                            
                            
                            389
                            
                            
                            
                            533Derivative
      collateral posted
                            
                            
                            563
                            
                            
                            
                            353Income
      taxes receivable
                            
                            
                            30
                            
                            
                            
                            194Prepayments
      and other current assets
                            
                            
                            230
                            
                            
                            
                            154Total
      current assets
                            
                            
                            3,988
                            
                            
                            
                            3,520Deferred
      debits and other assetsRegulatory
      assets
                            
                            
                            2,845
                            
                            
                            
                            2,567Nuclear
      decommissioning trust funds
                            
                            
                            1,044
                            
                            
                            
                            1,089Miscellaneous
      other property and investments
                            
                            
                            443
                            
                            
                            
                            446Goodwill
                            
                            
                            3,655
                            
                            
                            
                            3,655Other
      assets and deferred debits
                            
                            
                            292
                            
                            
                            
                            303Total
      deferred debits and other assets
                            
                            
                            8,279
                            
                            
                            
                            8,060Total
      assets
                            
                            $
                            30,903
                            
                            
                            $
                            29,873CAPITALIZATION
      AND LIABILITIESCommon
      stock equityCommon
      stock without par value, 500 million shares authorized, 279 million and
      264 million shares issued and outstanding, respectively
                            
                            $
                            6,764
                            
                            
                            $
                            6,206Unearned
      ESOP shares (1 million shares)
                            
                            
                            (17
                            )
                            
                            
                            (25
                            )Accumulated
      other comprehensive loss
                            
                            
                            (107
                            )
                            
                            
                            (116
                            )Retained
      earnings
                            
                            
                            2,621
                            
                            
                            
                            2,622Total
      common stock equity
                            
                            
                            9,261
                            
                            
                            
                            8,687Noncontrolling
      interests
                            
                            
                            6
                            
                            
                            
                            6Total
      equity
                            
                            
                            9,267
                            
                            
                            
                            8,693Preferred
      stock of subsidiaries
                            
                            
                            93
                            
                            
                            
                            93Long-term
      debt, affiliate
                            
                            
                            272
                            
                            
                            
                            272Long-term
      debt, net
                            
                            
                            11,133
                            
                            
                            
                            10,387Total
      capitalization
                            
                            
                            20,765
                            
                            
                            
                            19,445Current
      liabilitiesCurrent
      portion of long-term debt
                            
                            
                            100
                            
                            
                            
                            –Short-term
      debt
                            
                            
                            630
                            
                            
                            
                            1,050Accounts
      payable
                            
                            
                            780
                            
                            
                            
                            912Interest
      accrued
                            
                            
                            154
                            
                            
                            
                            167Dividends
      declared
                            
                            
                            174
                            
                            
                            
                            164Customer
      deposits
                            
                            
                            286
                            
                            
                            
                            282Derivative
      liabilities
                            
                            
                            556
                            
                            
                            
                            493Other
      current liabilities
                            
                            
                            383
                            
                            
                            
                            418Total
      current liabilities
                            
                            
                            3,063
                            
                            
                            
                            3,486Deferred
      credits and other liabilitiesNoncurrent
      income tax liabilities
                            
                            
                            888
                            
                            
                            
                            818Accumulated
      deferred investment tax credits
                            
                            
                            125
                            
                            
                            
                            127Regulatory
      liabilities
                            
                            
                            2,141
                            
                            
                            
                            2,181Asset
      retirement obligations
                            
                            
                            1,496
                            
                            
                            
                            1,471Accrued
      pension and other benefits
                            
                            
                            1,597
                            
                            
                            
                            1,594Capital
      lease obligations
                            
                            
                            230
                            
                            
                            
                            231Derivative
      liabilities
                            
                            
                            352
                            
                            
                            
                            269Other
      liabilities and deferred credits
                            
                            
                            246
                            
                            
                            
                            251Total
      deferred credits and other liabilities
                            
                            
                            7,075
                            
                            
                            
                            6,942Commitments
      and contingencies (Notes 14 and 15)Total
      capitalization and liabilities
                            
                            $
                            30,903
                            
                            
                            $
                            29,873See
      Notes to Progress Energy, Inc. Unaudited Condensed Consolidated Interim
      Financial Statements.


10




PROGRESS ENERGY, INC.UNAUDITED
      CONDENSED CONSOLIDATED STATEMENTS of CASH FLOWS(in
      millions)Three
      months ended March 31
                  
                  2009
                  
                  
                  2008Operating
      activitiesNet
      income
                  
                  $
                  183
                  
                  
                  $
                  214Adjustments
      to reconcile net income to net cash provided by operating
      activitiesDepreciation,
      amortization and accretion
                  
                  
                  313
                  
                  
                  
                  235Deferred
      income taxes and investment tax credits, net
                  
                  
                  (26
                  )
                  
                  
                  5Deferred
      fuel cost
                  
                  
                  128
                  
                  
                  
                  24Allowance
      for equity funds used during construction
                  
                  
                  (39
                  )
                  
                  
                  (23
                  )Other
      adjustments to net income
                  
                  
                  63
                  
                  
                  
                  (29
                  )Cash
      provided (used) by changes in operating assets and
    liabilitiesReceivables
                  
                  
                  5
                  
                  
                  
                  390Inventory
                  
                  
                  (62
                  )
                  
                  
                  4Derivative
      collateral posted
                  
                  
                  (216
                  )
                  
                  
                  –Prepayments
      and other current assets
                  
                  
                  (6
                  )
                  
                  
                  14Income
      taxes, net
                  
                  
                  183
                  
                  
                  
                  60Accounts
      payable
                  
                  
                  (76
                  )
                  
                  
                  79Other
      current liabilities
                  
                  
                  (62
                  )
                  
                  
                  (171
                  )Other
      assets and deferred debits
                  
                  
                  35
                  
                  
                  
                  (38
                  )Other
      liabilities and deferred credits
                  
                  
                  (28
                  )
                  
                  
                  13Net
      cash provided by operating activities
                  
                  
                  395
                  
                  
                  
                  777Investing
      activitiesGross
      property additions
                  
                  
                  (639
                  )
                  
                  
                  (618
                  )Nuclear
      fuel additions
                  
                  
                  (37
                  )
                  
                  
                  (41
                  )Proceeds
      from sales of discontinued operations and other assets, net of cash
      divested
                  
                  
                  –
                  
                  
                  
                  95Purchases
      of available-for-sale securities and other investments
                  
                  
                  (716
                  )
                  
                  
                  (488
                  )Proceeds
      from available-for-sale securities and other investments
                  
                  
                  706
                  
                  
                  
                  473Other
      investing activities
                  
                  
                  (5
                  )
                  
                  
                  (6
                  )Net
      cash used by investing activities
                  
                  
                  (691
                  )
                  
                  
                  (585
                  )Financing
      activitiesIssuance
      of common stock
                  
                  
                  545
                  
                  
                  
                  20Dividends
      paid on common stock
                  
                  
                  (173
                  )
                  
                  
                  (159
                  )Payments
      of short-term debt with original maturities greater than 90
      days
                  
                  
                  (29
                  )
                  
                  
                  (176
                  )Net
      (decrease) increase in short-term debt
                  
                  
                  (490
                  )
                  
                  
                  180Proceeds
      from issuance of long-term debt, net
                  
                  
                  1,338
                  
                  
                  
                  322Retirement
      of long-term debt
                  
                  
                  (400
                  )
                  
                  
                  (80
                  )Cash
      distributions to noncontrolling interests of consolidated
      subsidiaries
                  
                  
                  (1
                  )
                  
                  
                  (85
                  )Other
      financing activities
                  
                  
                  (42
                  )
                  
                  
                  (69
                  )Net
      cash provided (used) by financing activities
                  
                  
                  748
                  
                  
                  
                  (47
                  )Net
      increase in cash and cash equivalents
                  
                  
                  452
                  
                  
                  
                  145Cash
      and cash equivalents at beginning of period
                  
                  
                  180
                  
                  
                  
                  255Cash
      and cash equivalents at end of period
                  
                  $
                  632
                  
                  
                  $
                  400Supplemental
      disclosuresSignificant
      noncash transactionsAccrued
      property additions
                  
                  $
                  238
                  
                  
                  $
                  276See
      Notes to Progress Energy, Inc. Unaudited Condensed Consolidated Interim
      Financial Statements.


11


CAROLINA POWER & LIGHT
COMPANY


d/b/a
PROGRESS ENERGY CAROLINAS, INC.


UNAUDITED
CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS


March
31, 2009





UNAUDITED
      CONDENSED CONSOLIDATED STATEMENTS of INCOME(in
      millions)Three
      months ended March 31
                      
                      2009
                      
                      
                      2008Operating
      revenues
                      
                      $
                      1,178
                      
                      
                      $
                      1,068Operating
      expensesFuel
      used in electric generation
                      
                      
                      442
                      
                      
                      
                      356Purchased
      power
                      
                      
                      57
                      
                      
                      
                      49Operation
      and maintenance
                      
                      
                      259
                      
                      
                      
                      248Depreciation,
      amortization and accretion
                      
                      
                      117
                      
                      
                      
                      126Taxes
      other than on income
                      
                      
                      54
                      
                      
                      
                      50Other
                      
                      
                      –
                      
                      
                      
                      (1
                      )Total
      operating expenses
                      
                      
                      929
                      
                      
                      
                      828Operating
      income
                      
                      
                      249
                      
                      
                      
                      240Other
      income (expense)Interest
      income
                      
                      
                      2
                      
                      
                      
                      5Allowance
      for equity funds used during construction
                      
                      
                      9
                      
                      
                      
                      4Other,
      net
                      
                      
                      (7
                      )
                      
                      
                      –Total
      other income, net
                      
                      
                      4
                      
                      
                      
                      9Interest
      chargesInterest
      charges
                      
                      
                      57
                      
                      
                      
                      58Allowance
      for borrowed funds used during construction
                      
                      
                      (3
                      )
                      
                      
                      (2
                      )Total
      interest charges, net
                      
                      
                      54
                      
                      
                      
                      56Income
      before income tax
                      
                      
                      199
                      
                      
                      
                      193Income
      tax expense
                      
                      
                      71
                      
                      
                      
                      70Net
      income
                      
                      
                      128
                      
                      
                      
                      123Preferred
      stock dividend requirement
                      
                      
                      1
                      
                      
                      
                      1Net
      income available to common stockholders
                      
                      $
                      127
                      
                      
                      $
                      122See
      Notes to Progress Energy Carolina, Inc. Unaudited Condensed
      Consolidated Interim Financial Statements.


12




CAROLINA
      POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS,
      INC.UNAUDITED CONDENSED CONSOLIDATED BALANCE
      SHEETS(in
      millions)
                            
                            March
      31, 2009
                            
                            
                            December
      31, 2008ASSETSUtility
      plantUtility
      plant in service
                            
                            $
                            15,788
                            
                            
                            $
                            15,698Accumulated
      depreciation
                            
                            
                            (7,429
                            )
                            
                            
                            (7,352
                            )Utility
      plant in service, net
                            
                            
                            8,359
                            
                            
                            
                            8,346Held
      for future use
                            
                            
                            3
                            
                            
                            
                            3Construction
      work in progress
                            
                            
                            739
                            
                            
                            
                            660Nuclear
      fuel, net of amortization
                            
                            
                            359
                            
                            
                            
                            376Total
      utility plant, net
                            
                            
                            9,460
                            
                            
                            
                            9,385Current
      assetsCash
      and cash equivalents
                            
                            
                            21
                            
                            
                            
                            18Receivables,
      net
                            
                            
                            480
                            
                            
                            
                            502Receivables
      from affiliated companies
                            
                            
                            15
                            
                            
                            
                            29Notes
      receivable from affiliated companies
                            
                            
                            120
                            
                            
                            
                            55Inventory
                            
                            
                            651
                            
                            
                            
                            633Deferred
      fuel cost
                            
                            
                            163
                            
                            
                            
                            207Income
      taxes receivable
                            
                            
                            22
                            
                            
                            
                            98Prepayments
      and other current assets
                            
                            
                            50
                            
                            
                            
                            28Total
      current assets
                            
                            
                            1,522
                            
                            
                            
                            1,570Deferred
      debits and other assetsRegulatory
      assets
                            
                            
                            1,279
                            
                            
                            
                            1,243Nuclear
      decommissioning trust funds
                            
                            
                            651
                            
                            
                            
                            672Miscellaneous
      other property and investments
                            
                            
                            203
                            
                            
                            
                            197Other
      assets and deferred debits
                            
                            
                            95
                            
                            
                            
                            98Total
      deferred debits and other assets
                            
                            
                            2,228
                            
                            
                            
                            2,210Total
      assets
                            
                            $
                            13,210
                            
                            
                            $
                            13,165CAPITALIZATION
      AND LIABILITIESCommon
      stock equityCommon
      stock without par value, 200 million shares authorized, 160 million shares
      issued and outstanding
                            
                            $
                            2,092
                            
                            
                            $
                            2,083Unearned
      ESOP common stock
                            
                            
                            (17
                            )
                            
                            
                            (25
                            )Accumulated
      other comprehensive loss
                            
                            
                            (35
                            )
                            
                            
                            (35
                            )Retained
      earnings
                            
                            
                            2,204
                            
                            
                            
                            2,278Total
      common stock equity
                            
                            
                            4,244
                            
                            
                            
                            4,301Noncontrolling
      interests
                            
                            
                            4
                            
                            
                            
                            4Total
      equity
                            
                            
                            4,248
                            
                            
                            
                            4,305Preferred
      stock
                            
                            
                            59
                            
                            
                            
                            59Long-term
      debt, net
                            
                            
                            3,708
                            
                            
                            
                            3,509Total
      capitalization
                            
                            
                            8,015
                            
                            
                            
                            7,873Current
      liabilitiesShort-term
      debt
                            
                            
                            –
                            
                            
                            
                            110Accounts
      payable
                            
                            
                            315
                            
                            
                            
                            377Payables
      to affiliated companies
                            
                            
                            61
                            
                            
                            
                            82Interest
      accrued
                            
                            
                            56
                            
                            
                            
                            59Customer
      deposits
                            
                            
                            87
                            
                            
                            
                            82Derivative
      liabilities
                            
                            
                            60
                            
                            
                            
                            82Other
      current liabilities
                            
                            
                            186
                            
                            
                            
                            173Total
      current liabilities
                            
                            
                            765
                            
                            
                            
                            965Deferred
      credits and other liabilitiesNoncurrent
      income tax liabilities
                            
                            
                            1,162
                            
                            
                            
                            1,111Accumulated
      deferred investment tax credits
                            
                            
                            115
                            
                            
                            
                            115Regulatory
      liabilities
                            
                            
                            995
                            
                            
                            
                            987Asset
      retirement obligations
                            
                            
                            1,141
                            
                            
                            
                            1,122Accrued
      pension and other benefits
                            
                            
                            860
                            
                            
                            
                            856Other
      liabilities and deferred credits
                            
                            
                            157
                            
                            
                            
                            136Total
      deferred credits and other liabilities
                            
                            
                            4,430
                            
                            
                            
                            4,327Commitments
      and contingencies (Notes 14 and 15)Total
      capitalization and liabilities
                            
                            $
                            13,210
                            
                            
                            $
                            13,165See
      Notes to Progress Energy Carolinas, Inc. Unaudited Condensed
      Consolidated Interim Financial Statements.


13




CAROLINA
      POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS,
      INC.UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of CASH
      FLOWS(in
      millions)Three
      months ended March 31
                  
                  2009
                  
                  
                  2008Operating
      activitiesNet
      income
                  
                  $
                  128
                  
                  
                  $
                  123Adjustments
      to reconcile net income to net cash provided by operating
      activitiesDepreciation,
      amortization and accretion
                  
                  
                  141
                  
                  
                  
                  151Deferred
      income taxes and investment tax credits, net
                  
                  
                  32
                  
                  
                  
                  6Deferred
      fuel cost
                  
                  
                  61
                  
                  
                  
                  42Allowance
      for equity funds used during construction
                  
                  
                  (9
                  )
                  
                  
                  (4
                  )Other
      adjustments to net income
                  
                  
                  25
                  
                  
                  
                  17Cash
      provided (used) by changes in operating assets and
    liabilitiesReceivables
                  
                  
                  15
                  
                  
                  
                  38Receivables
      from affiliated companies
                  
                  
                  14
                  
                  
                  
                  13Inventory
                  
                  
                  (20
                  )
                  
                  
                  8Prepayments
      and other current assets
                  
                  
                  (14
                  )
                  
                  
                  17Income
      taxes, net
                  
                  
                  106
                  
                  
                  
                  50Accounts
      payable
                  
                  
                  (33
                  )
                  
                  
                  22Payables
      to affiliated companies
                  
                  
                  (21
                  )
                  
                  
                  (13
                  )Other
      current liabilities
                  
                  
                  (35
                  )
                  
                  
                  (28
                  )Other
      assets and deferred debits
                  
                  
                  18
                  
                  
                  
                  (19
                  )Other
      liabilities and deferred credits
                  
                  
                  (11
                  )
                  
                  
                  (4
                  )Net
      cash provided by operating activities
                  
                  
                  397
                  
                  
                  
                  419Investing
      activitiesGross
      property additions
                  
                  
                  (181
                  )
                  
                  
                  (173
                  )Nuclear
      fuel additions
                  
                  
                  (28
                  )
                  
                  
                  (41
                  )Purchases
      of available-for-sale securities and other investments
                  
                  
                  (420
                  )
                  
                  
                  (193
                  )Proceeds
      from available-for-sale securities and other investments
                  
                  
                  407
                  
                  
                  
                  185Changes
      in advances to affiliated companies
                  
                  
                  (65
                  )
                  
                  
                  (85
                  )Other
      investing activities
                  
                  
                  –
                  
                  
                  
                  (4
                  )Net
      cash used by investing activities
                  
                  
                  (287
                  )
                  
                  
                  (311
                  )Financing
      activitiesDividends
      paid on preferred stock
                  
                  
                  (1
                  )
                  
                  
                  (1
                  )Dividends
      paid to parent
                  
                  
                  (200
                  )
                  
                  
                  –Net
      decrease in short-term debt
                  
                  
                  (110
                  )
                  
                  
                  –Proceeds
      from issuance of long-term debt, net
                  
                  
                  595
                  
                  
                  
                  322Retirement
      of long-term debt
                  
                  
                  (400
                  )
                  
                  
                  –Changes
      in advances from affiliated companies
                  
                  
                  –
                  
                  
                  
                  (154
                  )Other
      financing activities
                  
                  
                  9
                  
                  
                  
                  (3
                  )Net
      cash (used) provided by financing activities
                  
                  
                  (107
                  )
                  
                  
                  164Net
      increase in cash and cash equivalents
                  
                  
                  3
                  
                  
                  
                  272Cash
      and cash equivalents at beginning of period
                  
                  
                  18
                  
                  
                  
                  25Cash
      and cash equivalents at end of period
                  
                  $
                  21
                  
                  
                  $
                  297Supplemental
      disclosuresSignificant
      noncash transactionsAccrued
      property additions
                  
                  $
                  77
                  
                  
                  $
                  76See
      Notes to Progress Energy Carolina, Inc. Unaudited Condensed Consolidated
      Interim Financial Statements.


14


FLORIDA POWER CORPORATION


d/b/a
PROGRESS ENERGY FLORIDA, INC.


UNAUDITED
CONDENSED INTERIM FINANCIAL STATEMENTS


March
31, 2009





UNAUDITED
      CONDENSED STATEMENTS of INCOME(in
      millions)Three
      months ended March 31
                    
                    2009
                    
                    
                    2008Operating
      revenues
                    
                    $
                    1,262
                    
                    
                    $
                    996Operating
      expensesFuel
      used in electric generation
                    
                    
                    512
                    
                    
                    
                    341Purchased
      power
                    
                    
                    160
                    
                    
                    
                    183Operation
      and maintenance
                    
                    
                    202
                    
                    
                    
                    203Depreciation,
      amortization and accretion
                    
                    
                    160
                    
                    
                    
                    76Taxes
      other than on income
                    
                    
                    88
                    
                    
                    
                    71Total
      operating expenses
                    
                    
                    1,122
                    
                    
                    
                    874Operating
      income
                    
                    
                    140
                    
                    
                    
                    122Other
      income (expense)Interest
      income
                    
                    
                    1
                    
                    
                    
                    1Allowance
      for equity funds used during construction
                    
                    
                    30
                    
                    
                    
                    19Other,
      net
                    
                    
                    –
                    
                    
                    
                    (2
                    )Total
      other income, net
                    
                    
                    31
                    
                    
                    
                    18Interest
      chargesInterest
      charges
                    
                    
                    67
                    
                    
                    
                    50Allowance
      for borrowed funds used during construction
                    
                    
                    (9
                    )
                    
                    
                    (6
                    )Total
      interest charges, net
                    
                    
                    58
                    
                    
                    
                    44Income
      before income tax
                    
                    
                    113
                    
                    
                    
                    96Income
      tax expense
                    
                    
                    24
                    
                    
                    
                    29Net
      income
                    
                    
                    89
                    
                    
                    
                    67Preferred
      stock dividend requirement
                    
                    
                    1
                    
                    
                    
                    1Net
      income available to common stockholders
                    
                    $
                    88
                    
                    
                    $
                    66See
      Notes to Progress Energy Florida, Inc. Unaudited Condensed
      Interim Financial Statements.


15




FLORIDA POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA,
      INC.UNAUDITED
      CONDENSED BALANCE SHEETS(in
      millions)
                  
                  March
      31, 2009
                  
                  
                  December
      31, 2008ASSETSUtility
      plantUtility
      plant in service
                  
                  $
                  10,630
                  
                  
                  $
                  10,449Accumulated
      depreciation
                  
                  
                  (3,950
                  )
                  
                  
                  (3,885
                  )Utility
      plant in service, net
                  
                  
                  6,680
                  
                  
                  
                  6,564Held
      for future use
                  
                  
                  35
                  
                  
                  
                  35Construction
      work in progress
                  
                  
                  2,234
                  
                  
                  
                  2,085Nuclear
      fuel, net of amortization
                  
                  
                  107
                  
                  
                  
                  106Total
      utility plant, net
                  
                  
                  9,056
                  
                  
                  
                  8,790Current
      assetsCash
      and cash equivalents
                  
                  
                  20
                  
                  
                  
                  19Receivables,
      net
                  
                  
                  362
                  
                  
                  
                  362Receivables
      from affiliated companies
                  
                  
                  7
                  
                  
                  
                  15Inventory
                  
                  
                  650
                  
                  
                  
                  606Regulatory
      assets
                  
                  
                  226
                  
                  
                  
                  326Derivative
      collateral posted
                  
                  
                  535
                  
                  
                  
                  335Prepayments
      and other current assets
                  
                  
                  159
                  
                  
                  
                  139Total
      current assets
                  
                  
                  1,959
                  
                  
                  
                  1,802Deferred
      debits and other assetsRegulatory
      assets
                  
                  
                  1,567
                  
                  
                  
                  1,324Nuclear
      decommissioning trust funds
                  
                  
                  393
                  
                  
                  
                  417Miscellaneous
      other property and investments
                  
                  
                  36
                  
                  
                  
                  37Other
      assets and deferred debits
                  
                  
                  82
                  
                  
                  
                  101Total
      deferred debits and other assets
                  
                  
                  2,078
                  
                  
                  
                  1,879Total
      assets
                  
                  $
                  13,093
                  
                  
                  $
                  12,471CAPITALIZATION
      AND LIABILITIESCommon
      stock equityCommon
      stock without par value, 60 million shares authorized,100
      shares issued and outstanding
                  
                  $
                  1,273
                  
                  
                  $
                  1,116Accumulated
      other comprehensive loss
                  
                  
                  (1
                  )
                  
                  
                  (1
                  )Retained
      earnings
                  
                  
                  2,372
                  
                  
                  
                  2,284Total
      common stock equity
                  
                  
                  3,644
                  
                  
                  
                  3,399Preferred
      stock
                  
                  
                  34
                  
                  
                  
                  34Long-term
      debt, net
                  
                  
                  4,182
                  
                  
                  
                  4,182Total
      capitalization
                  
                  
                  7,860
                  
                  
                  
                  7,615Current
      liabilitiesShort-term
      debt
                  
                  
                  130
                  
                  
                  
                  371Notes
      payable to affiliated companies
                  
                  
                  514
                  
                  
                  
                  72Accounts
      payable
                  
                  
                  445
                  
                  
                  
                  514Payables
      to affiliated companies
                  
                  
                  52
                  
                  
                  
                  55Interest
      accrued
                  
                  
                  56
                  
                  
                  
                  51Customer
      deposits
                  
                  
                  199
                  
                  
                  
                  200Derivative
      liabilities
                  
                  
                  496
                  
                  
                  
                  380Other
      current liabilities
                  
                  
                  169
                  
                  
                  
                  128Total
      current liabilities
                  
                  
                  2,061
                  
                  
                  
                  1,771Deferred
      credits and other liabilitiesNoncurrent
      income tax liabilities
                  
                  
                  701
                  
                  
                  
                  634Accumulated
      deferred investment tax credits
                  
                  
                  10
                  
                  
                  
                  12Regulatory
      liabilities
                  
                  
                  1,029
                  
                  
                  
                  1,076Asset
      retirement obligations
                  
                  
                  355
                  
                  
                  
                  349Accrued
      pension and other benefits
                  
                  
                  495
                  
                  
                  
                  494Capital
      lease obligations
                  
                  
                  215
                  
                  
                  
                  216Derivative
      liabilities
                  
                  
                  275
                  
                  
                  
                  209Other
      liabilities and deferred credits
                  
                  
                  92
                  
                  
                  
                  95Total
      deferred credits and other liabilities
                  
                  
                  3,172
                  
                  
                  
                  3,085Commitments
      and contingencies (Notes 14 and 15)Total
      capitalization and liabilities
                  
                  $
                  13,093
                  
                  
                  $
                  12,471See
      Notes to Progress Energy Florida, Inc. Unaudited Condensed Interim
      Financial Statements.


16




FLORIDA
      POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA, INC.UNAUDITED CONDENSED STATEMENTS of CASH
      FLOWS(in
      millions)Three
      months ended March 31
                  
                  2009
                  
                  
                  2008Operating
      activitiesNet
      income
                  
                  $
                  89
                  
                  
                  $
                  67Adjustments
      to reconcile net income to net cash provided by operating
      activitiesDepreciation,
      amortization and accretion
                  
                  
                  166
                  
                  
                  
                  80Deferred
      income taxes and investment tax credits, net
                  
                  
                  (18
                  )
                  
                  
                  15Deferred
      fuel cost (credit)
                  
                  
                  67
                  
                  
                  
                  (18
                  )Allowance
      for equity funds used during construction
                  
                  
                  (30
                  )
                  
                  
                  (19
                  )Other
      adjustments to net income
                  
                  
                  32
                  
                  
                  
                  6Cash
      (used) provided by changes in operating assets and
    liabilitiesReceivables
                  
                  
                  (10
                  )
                  
                  
                  40Receivables
      from affiliated companies
                  
                  
                  8
                  
                  
                  
                  (7
                  )Inventory
                  
                  
                  (43
                  )
                  
                  
                  (8
                  )Derivative
      collateral posted
                  
                  
                  (204
                  )
                  
                  
                  –Prepayments
      and other current assets
                  
                  
                  2
                  
                  
                  
                  (3
                  )Income
      taxes, net
                  
                  
                  72
                  
                  
                  
                  43Accounts
      payable
                  
                  
                  (43
                  )
                  
                  
                  70Payables
      to affiliated companies
                  
                  
                  (3
                  )
                  
                  
                  (33
                  )Other
      current liabilities
                  
                  
                  19
                  
                  
                  
                  35Other
      assets and deferred debits
                  
                  
                  17
                  
                  
                  
                  (17
                  )Other
      liabilities and deferred credits
                  
                  
                  (9
                  )
                  
                  
                  19Net
      cash provided by operating activities
                  
                  
                  112
                  
                  
                  
                  270Investing
      activitiesGross
      property additions
                  
                  
                  (462
                  )
                  
                  
                  (446
                  )Nuclear
      fuel additions
                  
                  
                  (9
                  )
                  
                  
                  –Purchases
      of available-for-sale securities and other investments
                  
                  
                  (273
                  )
                  
                  
                  (247
                  )Proceeds
      from available-for-sale securities and other investments
                  
                  
                  279
                  
                  
                  
                  247Changes
      in advances to affiliated companies
                  
                  
                  –
                  
                  
                  
                  149Proceeds
      from sales of assets to affiliated companies
                  
                  
                  –
                  
                  
                  
                  8Other
      investing activities
                  
                  
                  (2
                  )
                  
                  
                  (2
                  )Net
      cash used by investing activities
                  
                  
                  (467
                  )
                  
                  
                  (291
                  )Financing
      activitiesDividends
      paid on preferred stock
                  
                  
                  (1
                  )
                  
                  
                  (1
                  )Net
      decrease in short-term debt
                  
                  
                  (241
                  )
                  
                  
                  –Retirement
      of long-term debt
                  
                  
                  –
                  
                  
                  
                  (80
                  )Changes
      in advances from affiliated companies
                  
                  
                  442
                  
                  
                  
                  95Contributions
      from parent
                  
                  
                  155
                  
                  
                  
                  –Other
      financing activities
                  
                  
                  1
                  
                  
                  
                  –Net
      cash provided by financing activities
                  
                  
                  356
                  
                  
                  
                  14Net
      increase (decrease) in cash and cash equivalents
                  
                  
                  1
                  
                  
                  
                  (7
                  )Cash
      and cash equivalents at beginning of period
                  
                  
                  19
                  
                  
                  
                  23Cash
      and cash equivalents at end of period
                  
                  $
                  20
                  
                  
                  $
                  16Supplemental
      disclosuresSignificant
      noncash transactionsAccrued
      property additions
                  
                  $
                  160
                  
                  
                  $
                  198See
      Notes to Progress Energy Florida, Inc. Unaudited Condensed 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 CONDENSED INTERIM FINANCIAL
STATEMENTS





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





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




Registrant
            Applicable NotesPEC
            1,
      2, 4, 6, 8 through 11, and 13 through 15PEF
            1,
      2, 4, 6, 8 through 11, and 13 through
  15


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







1.
            ORGANIZATION AND
      SUMMARY OF SIGNIFICANT ACCOUNTING
  POLICIES




A.      ORGANIZATION




In this
report, Progress Energy, which includes Progress Energy, Inc. holding company
(the Parent) and its regulated and nonregulated subsidiaries on a consolidated
basis, is at times referred to as “we,” “us” or “our.” When discussing Progress
Energy’s financial information, it necessarily includes the results of Carolina
Power & Light Company d/b/a Progress Energy Carolinas, Inc. (PEC) and
Florida Power Corporation d/b/a Progress Energy Florida, Inc. (PEF)
(collectively, the Utilities). The term “Progress Registrants” refers to each of
the three separate registrants: Progress Energy, PEC and PEF. The information in
these combined notes relates to each of the Progress Registrants as noted in the
Index to the Combined Notes. However, neither of the Utilities makes any
representation as to information related solely to Progress Energy or the
subsidiaries of Progress Energy other than itself.




PROGRESS
ENERGY





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




Our
reportable segments are PEC and PEF, both of which are primarily engaged in the
generation, transmission, distribution and sale of electricity. The Corporate
and Other segment primarily includes amounts applicable to the activities of the
Parent and Progress Energy Service Company, LLC (PESC) and other miscellaneous
nonregulated businesses that do not separately meet the quantitative disclosure
requirements as a reportable business segment. See Note 12 for further
information about our segments.




PEC





PEC is a
regulated public utility primarily engaged in the generation, transmission,
distribution and sale of electricity in portions of North Carolina and South
Carolina. PEC’s subsidiaries are involved in insignificant nonregulated business
activities. PEC is subject to the regulatory provisions of the North Carolina
Utilities Commission (NCUC), Public Service Commission of South Carolina
(SCPSC), the United States Nuclear Regulatory Commission (NRC) and the
FERC.





PEF





PEF is a
regulated public utility primarily engaged in the generation, transmission,
distribution and sale of electricity in west central Florida. PEF is subject to
the regulatory provisions of the Florida Public Service Commission (FPSC), the
NRC and the FERC.





B.      BASIS
OF PRESENTATION




These
financial statements have been prepared in accordance with accounting principles
generally accepted in the United States of America (GAAP) for interim financial
information and with the instructions to Form 10-Q and Regulation S-X.
Accordingly, they do not include all of the information and footnotes required
by GAAP for annual financial statements. The December 31, 2008 condensed balance
sheet data was derived from audited financial statements but does not include
all disclosures required by GAAP. Because the accompanying interim financial
statements do not include all of the information and footnotes required by GAAP
for annual financial statements, they should be read in conjunction with the
audited financial statements and notes thereto included in the Progress
Registrants’ annual report on Form 10-K for the fiscal year ended December 31,
2008 (2008 Form 10-K).




19




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)
                      
                      2009
                      
                      
                      2008Progress
      Energy
                      
                      $
                      79
                      
                      
                      $
                      64PEC
                      
                      
                      26
                      
                      
                      
                      24PEF
                      
                      
                      53
                      
                      
                      
                      40





The
amounts included in these financial statements are unaudited but, in the opinion
of management, reflect all adjustments necessary to fairly present the Progress
Registrants’ financial position and results of operations for the interim
periods. Unless otherwise noted, all adjustments are normal and recurring in
nature. Due to seasonal weather variations, the impact of regulatory orders
received, and the timing of outages of electric generating units, especially
nuclear-fueled units, the results of operations for interim periods are not
necessarily indicative of amounts expected for the entire year or future
periods.




In
preparing financial statements that conform to GAAP, management must make
estimates and assumptions that affect the reported amounts of assets and
liabilities, the reported amounts of revenues and expenses and the disclosure of
contingent assets and liabilities at the date of the financial statements.
Actual results could differ from those estimates.




Certain
amounts for 2008 have been reclassified to conform to the 2009
presentation.




C.      CONSOLIDATION
OF VARIABLE INTEREST ENTITIES




We
consolidate all voting interest entities in which we own a majority voting
interest and all variable interest entities (VIEs) for which we are the primary
beneficiary in accordance with Financial Accounting Standards Board (FASB)
Interpretation No. 46R, “Consolidation of Variable Interest Entities – an
Interpretation of ARB No. 51” (FIN 46R).




In
general, we determine whether we are the primary beneficiary of a VIE through a
qualitative analysis of risk that identifies which variable interest holder
absorbs the majority of the financial risk and variability of the VIE. In
performing this analysis, we consider all relevant facts and circumstances,
including: the design and activities of the VIE, the terms of the contracts the
VIE has entered into, the nature of the VIE’s variable interests issued and how
they were negotiated with or marketed to potential investors, and which parties
participated significantly in the design or redesign of the entity. If the
qualitative analysis is inconclusive, a specific quantitative analysis is
performed in accordance with FIN 46R. For purposes of the following disclosures,
the maximum loss amounts represent the maximum exposure that would be absorbed
by the Progress Registrants in the event that all of the assets of the VIE are
deemed worthless, including any additional costs that the Progress Registrants
would incur.




PROGRESS
ENERGY




In
addition to the following variable interests listed for PEC and PEF, Progress
Energy, through its subsidiary Progress Fuels Corporation (Progress Fuels), is
the primary beneficiary of, and consolidates, Ceredo Synfuel, LLC (Ceredo), a
coal-based solid synthetic fuels production facility that qualified for federal
tax credits under Section 45K of the Internal Revenue Code (the Code). See Note
1C in the 2008 Form 10-K for discussion of our variable interest in Ceredo.
There were no changes to our assessment of the primary beneficiary during 2008
or for the period ended March 31, 2009. No financial or other support has been
provided to Ceredo during the periods presented. At March 31, 2009, we had no
assets and $20 million of liabilities related to the legal and tax
indemnifications provided to the buyer included in other liabilities and
deferred credits in the Progress Energy Consolidated Balance Sheets. The
ultimate resolution of the indemnifications could result in adjustments to the
loss on disposal in future periods. The creditors of Ceredo do not have recourse
to the general credit of Progress Energy. See Note 3D for additional information
on the disposal of Ceredo and Note 15B for a general discussion of
guarantees.




20




PEC




VARIABLE
INTEREST ENTITIES FOR WHICH PEC IS THE PRIMARY BENEFICIARY




PEC is
the primary beneficiary of, and consolidates, two limited partnerships that
qualify for federal affordable housing and historic tax credits under Section 42
of the Code. PEC’s variable interests are debt and equity investments in the two
VIEs. PEC performed quantitative analyses to determine the primary beneficiaries
of the two VIEs. The primary factors in the analyses were the estimated economic
lives of the partnerships and their net cash flow projections, estimates of
available tax credits, and the likelihood of default on debt and other
commitments. There were no changes to PEC’s assessment of the primary
beneficiary during 2008 or for the period ended March 31, 2009. No financial or
other support has been provided to the VIEs during the periods presented. At
March 31, 2009, PEC had assets of $40 million, substantially all of which was
reflected in miscellaneous other property and investments, $16 million in
long-term debt, $7 million in other liabilities and deferred credits and $4
million in accounts payable in the PEC Consolidated Balance Sheets related to
the two VIEs. The assets of the two VIEs are collateral for, and can only be
used to settle, their obligations. The creditors of these VIEs do not have
recourse to the general credit of PEC and there are no other arrangements that
could expose PEC to losses.




OTHER
VARIABLE INTERESTS




PEC has
an equity investment in, and consolidates, one limited partnership investment
fund that invests in 17 low-income housing partnerships that qualify for federal
and state tax credits. The investment fund accounts for the 17 partnerships on
the equity method of accounting. PEC also has an interest in one power plant
resulting from long-term power purchase contracts. PEC’s only significant
exposure to variability from the power purchase contracts results from
fluctuations in the market price of fuel used by the entity’s plants to produce
the power purchased by PEC. We are able to recover these fuel costs under PEC’s
fuel clause. The generation capacity of the entity’s power plant is
approximately 847 megawatts (MW). PEC has requested the necessary information to
determine if the investment fund’s 17 partnerships and the power plant owner are
VIEs or to identify the primary beneficiaries; all entities from which the
necessary financial information was requested declined to provide the
information to PEC, and, accordingly, PEC has applied the information scope
exception 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 power plant and the investment
fund consolidating the 17 partnerships would result in increases to total
assets, long-term debt and other liabilities, but would have an insignificant or
no impact on PEC’s common stock equity, net earnings or cash flows. However,
because PEC has not received any financial information from the counterparties,
the impact cannot be determined at this time.




PEF




The
following information is provided for PEF’s significant variable interests in
VIEs for which PEF is not the primary beneficiary:




PEF has a
prepayment clause in a building capital lease with a special purpose entity that
is a VIE. In accordance with the lease agreement, PEF is not required to make
any lease payments over the last 20 years of the lease, during which period $51
million of rental expense will be recorded in the PEF Statements of Income. The
prepayment clause is PEF’s only variable interest in the VIE and, therefore,
PEF’s exposure to loss primarily relates to the recovery of the prepayments
through future use of the rental property. PEF performed qualitative and
quantitative analyses and concluded that it is not the primary beneficiary of
the VIE. The primary factors in the analyses were the lease term, the fact that
the lease payments are not variable interests, the likelihood of construction
and casualty risks to the building and the existence of insurance to offset
those risks, and the estimated fair value of the building at the end of the
lease term. There were no changes to PEF’s assessment of the primary beneficiary
during 2008 or for the period ended March 31, 2009. No financial or other
support has been provided to the VIE during the periods presented. At March 31,
2009, PEF had a $5 million prepayment included in other assets and deferred
debits on the PEF Balance Sheets. No liabilities associated with the prepayment
clause were recorded. The aggregate maximum exposure to loss at March 31, 2009,
is $51 million, which represents the loss if the maximum prepayment of rent at
the end of year 20 was not recovered through future use of the rental property
or from third-party insurers at that time.




PEF has a
residual value guarantee in an operating railcar lease agreement with a special
purpose entity that is a VIE. The lease agreement has an early termination
clause that permits PEF to terminate the lease in certain




21




circumstances.
If PEF terminates the lease in accordance with the agreement, it must sell the
railcars and remit the proceeds to the lessor plus any amount for which the
residual value guarantee exceeds the realized value of the equipment. The
residual value guarantee is PEF’s primary variable interest in the VIE and,
therefore, PEF’s exposure to loss is from the potential decrease in the fair
value of the railcars. PEF performed qualitative and quantitative analyses and
concluded that it is not the primary beneficiary of the VIE. The primary factors
in the analyses were the terms of the lease, the probability of exercising the
early termination clause, and the estimated fair value of the railcars. There
were no changes to PEF’s assessment of the primary beneficiary during 2008 or
for the period ended March 31, 2009. No financial or other support has been
provided to the VIE during the periods presented. No liabilities associated with
the residual value guarantee were recorded at March 31, 2009, because the early
termination clause was not exercised. The aggregate maximum exposure to loss at
March 31, 2009, is $18 million, which represents the maximum loss if the early
termination clause were exercised in 2009 and the related railcars were deemed
worthless.







2.
            NEW ACCOUNTING
      STANDARDS




FSP
FAS 157-2, “Effective Date of FASB Statement No. 157”




In
February 2008, the FASB issued FASB Staff Position (FSP) FAS 157-2, “Effective
Date of FASB Statement No. 157” (FSP FAS 157-2), which for us and the Utilities
delayed the effective date of SFAS No. 157, “Fair Value Measurements” (SFAS No.
157), for all nonfinancial assets and nonfinancial liabilities, except for those
that are recognized or disclosed at fair value in the financial statements on a
recurring basis (at least annually), until January 1, 2009. The adoption of SFAS
No. 157, including FSP FAS 157-2, did not have a material impact on our or the
Utilities' financial position or results of operations. See Note 9 for
information regarding our implementation of SFAS No. 157 and FSP FAS
157-2.




SFAS
No. 141R, “Business Combinations”




In
December 2007, the FASB issued SFAS Statement No. 141R, “Business Combinations”
(SFAS No. 141R), which introduces significant changes in the accounting for
business acquisitions. SFAS No. 141R considerably broadens the definition of a
“business” and a “business combination,” which should result in an increased
number of transactions or other events that will qualify as business
combinations. Other significant changes include the expensing of all
acquisition-related transaction costs and most acquisition-related restructuring
costs, the fair value remeasurement of certain earn-out arrangements and the
discontinuance of the expense at acquisition of acquired-in-process research and
development. SFAS No. 141R was effective for us for business combinations for
which the acquisition date is on or after January 1, 2009. The adoption of SFAS
No. 141R did not have any impact on our or the Utilities' financial
position or results of operations.




SFAS
No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an
amendment of ARB No. 51”




In
conjunction with the issuance of SFAS No. 141R, in December 2007, the FASB
issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial
Statements, an amendment of ARB No. 51” (SFAS No. 160), which introduces
significant changes in the accounting for noncontrolling interests in a
partially owned consolidated subsidiary. SFAS No. 160 was adopted concurrently
with the effective date of SFAS No. 141R, which for us was January 1, 2009. See
Note 6B for information regarding our first quarter 2009 implementation of SFAS
No. 160. The adoption of SFAS No. 160 resulted in a change in presentation
of the financial statements and additional disclosures but did not have a
material impact on our or the Utilities' financial position or results of
operations.




SFAS
No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an
amendment of FASB Statement No. 133”




On
January 1, 2009, we implemented SFAS Statement No. 161, “Disclosures about
Derivative Instruments and Hedging Activities – an amendment of FASB Statement
No. 133” (SFAS No. 161), which requires entities to provide enhanced disclosures
about how and why an entity uses derivative instruments, how derivative
instruments and related hedged items are accounted for under Statement 133 and
its related interpretations and how derivative instruments and related hedged
items affect an entity’s financial position, financial performance and cash
flows. See Note 11 for information regarding our first quarter 2009
implementation of SFAS No. 161. The adoption of SFAS No. 161 did not have a
material impact on our or the Utilities' financial position or results of
operations.




22




FSP
EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment
Transactions Are Participating Securities”





On
January 1, 2009, we implemented FSP EITF 03-6-1, “Determining Whether
Instruments Granted in Share-Based Payment Transactions Are Participating
Securities” (FSP EITF 03-6-1), which requires that certain unvested share-based
payment awards (e.g. restricted stock) that contain nonforfeitable rights to
dividends or dividend equivalents be included in the computation of earnings per
share using the two-class method. FSP EITF 03-6-1 required a retrospective
adjustment for all prior-period earnings per share data. The adoption of FSP
EITF 03-6-1 did not have a material impact on our or the Utilities' financial
position, results of operations or earnings per share amounts.




New
FSPs for Fair Value Measurement and Disclosures and Other-Than-Temporary
Impairments





In April
2009, the FASB issued three FSPs for guidance on accounting for fair value
measurement and other-than-temporary impairments.





FSP FAS
157-4, “Determining Fair Value When the Volume and Level of Activity for the
Asset or Liability Have Significantly Decreased and Identifying Transactions
That are Not Orderly,” provides guidance on determining fair value when market
activity has decreased for an asset or liability. FSP FAS 107-1 and APB 28-1,
“Interim Disclosures About Fair Value of Financial Instruments,” increases the
frequency of fair value disclosures required by SFAS No. 107, “Disclosures of
Fair Value of Financial Instruments,” from annual only to
quarterly.




FSP FAS
115-2 and FAS 124-2, “Recognition and Presentation of Other-Than-Temporary
Impairments” (FSP FAS 115-2), revises the recognition and reporting requirements
for other-than-temporary impairments of debt securities and increases the
frequency of disclosures for debt and equity securities. Under FSP FAS 115-2, if
an entity intends to sell an impaired debt security or more likely than not will
be required to sell the security before recovery of its amortized cost basis
less any current-period credit loss, an other-than-temporary impairment must be
recognized currently in earnings equal to the difference between the
investment’s amortized cost and its fair value at the balance sheet
date.




The three
FSPs are effective for us for the three month period ending June 30, 2009. Their
adoption will change certain disclosures in the notes to the financial
statements, but we do not expect their adoption to have a material impact on our
or the Utilities’ financial position or results of operations.




FSP
FAS 132R-1, “Employers’ Disclosures about Post Retirement Benefit Plan
Assets”





In
December 2008, the FASB issued FSP FAS 132R-1, “Employers’ Disclosures about
Post Retirement Benefit Plan Assets” (FSP FAS 132R-1), which requires additional
disclosures on the investment allocation decision making process, the fair value
of each major category of plan assets and the inputs and valuation techniques
used to remeasure the fair value of plan assets. FSP FAS 132R-1 is effective for
us on December 31, 2009. The adoption of FSP FAS 132R-1 will change certain
disclosures in the notes to the financial statements but we do not expect the
adoption of FSP FAS 132R-1 to have a material impact on our or the Utilities’
financial position or results of operations.







3.
            DIVESTITURES




A.
            TERMINALS
      OPERATIONS AND SYNTHETIC FUELS
BUSINESSES




On March
7, 2008, we sold coal terminals and docks in West Virginia and Kentucky
(Terminals) for $71 million in gross cash proceeds. The terminals had a total
annual capacity in excess of 40 million tons for transloading, blending and
storing coal and other commodities. Proceeds from the sale were used for general
corporate purposes. During the three months ended March 31, 2008, we recorded an
after-tax gain of $46 million on the sale of these assets. The accompanying
consolidated financial statements reflect the operations of Terminals as
discontinued operations.




Prior to
2008, we had substantial operations associated with the production of coal-based
solid synthetic fuels (Synthetic Fuels) as defined under Section 29 (Section 29)
of the Code and as redesignated effective 2006 as Section 45K of the Code
(Section 45K and collectively, Section 29/45K). The production and sale of these
products qualified for federal income tax credits so long as certain
requirements were satisfied. As a result of the expiration of the tax credit
program, all of our synthetic fuels businesses were abandoned and all operations
ceased as of




23




December
31, 2007. The accompanying consolidated statements of income reflect the
abandoned operations of our synthetic fuels businesses as discontinued
operations.





Results
of discontinued operations for the three months ended March 31 for Terminals and
Synthetic Fuels were as follows:




(in
      millions)
                  
                  2008Revenues
                  
                  $
                  17Earnings
      before income taxes and noncontrolling interest
                  
                  
                  10Income
      tax benefit, including tax credits and tax levelization
                  
                  
                  3Earnings
      attributable to noncontrolling interests of synthetic fuel
                  
                  
                  (1
                  )Net
      earnings from discontinued operations attributable to controlling
      interests
                  
                  
                  12Gain
      on disposal of discontinued operations, including income tax expense of
      $7
                  
                  
                  46Earnings
      from discontinued operations attributable to controlling
      interests
                  
                  $
                  58


B.
            COAL
      MINING BUSINESSES




On March
7, 2008, we sold the remaining operations of Progress Fuels subsidiaries engaged
in the coal mining business (Coal Mining) for gross cash proceeds of $23
million. Proceeds from the sale were used for general corporate purposes. These
assets included Powell Mountain Coal Co. and Dulcimer Land Co., which consisted
of about 30,000 acres in Lee County, Va. and Harlan County, Ky. As a result of
the sale, during the three months ended March 31, 2008, we recorded an after-tax
gain of $7 million on the sale of these assets.




The
accompanying consolidated financial statements reflect Coal Mining as
discontinued operations. Results of Coal Mining discontinued operations for the
three months ended March 31 were as follows:




(in
      millions)
                      
                      2008Revenues
                      
                      $
                      2Loss
      before income taxes
                      
                      
                      (7
                      )Income
      tax benefit
                      
                      
                      1Net
      loss from discontinued operations
                      
                      
                      (6
                      )Gain
      on disposal of discontinued operations, including income tax expense of
      $2
                      
                      
                      7Earnings
      from discontinued operations
                      
                      $
                      1


C.
            OTHER
      DIVERSIFIED BUSINESSES




Also
included in discontinued operations in 2008 are amounts related to adjustments
of our prior sales of other diversified businesses, primarily natural gas
drilling and production business (Gas) and Progress Rail Services Corporation
(Progress Rail). These adjustments are mainly due to the finalization of working
capital and in connection with guarantees and indemnifications provided by
Progress Fuels and Progress Energy for certain legal, tax and environmental
matters (See Note 15B). The ultimate resolution of these matters could result in
additional adjustments in future periods. For the three months ended March 31,
2008, we recorded additional gains of $1 million, net of tax.




D.
            CEREDO
      SYNTHETIC FUELS INTERESTS




On March
30, 2007, our Progress Fuels subsidiary disposed of its 100 percent ownership
interest in Ceredo, a subsidiary that produced and sold qualifying coal-based
solid synthetic fuels, to a third-party buyer. In addition, we entered into an
agreement to operate the Ceredo facility on behalf of the buyer. At closing, we
received cash proceeds of $10 million and a non-recourse note receivable of $54
million. Payments on the note were due as we produced and sold qualifying
synthetic fuels on behalf of the buyer. In accordance with the terms of the
agreement, we received payments on the note related to 2007 production of $49
million during the year ended December 31, 2007, and $5 million during the three
months ended March 31, 2008. The note had an interest rate equal to the
three-month London Inter Bank Offering Rate (LIBOR) rate plus 1%. The estimated
fair value of the note at the inception of the transaction was $48 million.
Under the terms of the agreement, the purchase price was reduced by $7 million
during the three months ended March 31, 2008, based on the final value of the
2007 Section 29/45K tax credits.




24




During
the three months ended March 31, 2008, we recognized previously deferred gains
on disposal of $5 million based on the final value of the 2007 Section 29/45K
tax credits. The operations of Ceredo ceased as of December 31, 2007, and are
recorded as discontinued operations for all periods presented. See discussion of
the abandonment of our synthetic fuels operations at Note 3A. In connection with
the disposal, Progress Fuels and Progress Energy provided guarantees and
indemnifications for certain legal and tax matters to the buyer. The ultimate
resolution of these matters could result in adjustments to the loss on disposal
in future periods. See general discussion of guarantees at Note
15B.







4.
            REGULATORY
      MATTERS




A.
            PEC
      RETAIL RATE MATTERS




FUEL
COST RECOVERY




On May 7,
2009, PEC filed with the SCPSC for a decrease in the fuel rate charged to its
South Carolina ratepayers. PEC is asking the SCPSC to approve a $13 million
decrease in fuel rates driven by declining fuel prices. If approved, the
decrease would take effect July 1, 2009, and would decrease residential electric
bills by $2.05 per 1,000 kilowatt-hours (kWh), or 2.0 percent, for fuel cost
recovery. A hearing on the matter has been scheduled by the SCPSC for June 11,
2009. We cannot predict the outcome of this matter.




DEMAND-SIDE
MANAGEMENT AND ENERGY-EFFICIENCY COST RECOVERY




During
2007, the North Carolina legislature passed comprehensive energy legislation,
which became law on August 20, 2007. Among other provisions, the law allows the
utility to recover the costs of demand-side management (DSM) and
energy-efficiency programs through an annual DSM clause. The law allows PEC to
capitalize those costs intended to produce future benefits and authorizes the
NCUC to approve other forms of financial incentives to the utility for DSM and
energy-efficiency programs. DSM programs include, but are not limited to, any
program or initiative that shifts the timing of electricity use from peak to
nonpeak periods and includes load management, electricity system and operating
controls, direct load control, interruptible load and electric system equipment
and operating controls. PEC has implemented a series of DSM and
energy-efficiency programs and will continue to pursue additional programs. In
2008, PEC filed for NCUC approval of multiple DSM and energy-efficiency
programs. The majority of the programs has been approved by the NCUC or is
pending further review. We cannot predict the outcome of the DSM and
energy-efficiency filings pending further approval by the NCUC or whether the
programs will produce the expected operational and economic
results.




On June
6, 2008, and as subsequently amended, PEC filed an application with the NCUC for
approval of a DSM and energy-efficiency clause to recover the costs of these
programs and a return on the costs. On November 14, 2008, the NCUC issued an
order allowing PEC to implement the rates requested in PEC’s November 14, 2008
revision to its initial application. The new rates were implemented on December
1, 2008 increasing residential electrical bills by $0.74 per 1,000 kWh, or 0.8
percent. The new rates will be subject to true-up when a final order is received
in the cost-recovery proceeding. On December 9, 2008, the North Carolina Public
Staff filed an Agreement and Stipulation of Partial Settlement with PEC and some
of the other parties to the proceedings. The NCUC held a hearing on the matter
on January 7, 2009. We cannot predict the outcome of this matter.




PEC filed
a petition on November 30, 2007, with the SCPSC seeking authorization to create
a deferred account for DSM and energy-efficiency expenses. On December 21, 2007,
the SCPSC issued an order granting PEC’s petition. On June 27, 2008, PEC filed
an application with the SCPSC to establish procedures that encourage investment
in cost-effective energy-efficient technologies and energy conservation programs
and approve the establishment of an annual rider to allow recovery for all costs
associated with such programs, as well as the recovery of appropriate incentives
for investing in such programs. On January 23, 2009, PEC filed a Stipulation
Agreement between PEC and some of the other parties to the
proceeding.   On
May 6, 2009, the SCPSC approved the Stipulation
Agreement.




25




PEF
RETAIL RATE MATTERS




BASE
RATE FILING




As a
result of a base rate proceeding in 2005, PEF is party to a base rate settlement
agreement that was effective with the first billing cycle of January 2006 and
will remain in effect through the last billing cycle of December
2009.




On March
20, 2009, in anticipation of the expiration of its current base rate settlement
agreement, PEF filed with the FPSC a proposal for an increase in base rates
effective January 1, 2010. In its filing, PEF requested the FPSC to approve
calendar year 2010 as the projected test period for setting new base rates and
approve annual rate relief for PEF of $499 million, which includes PEF’s
petition for a combined $76 million of new base rates in 2009 as discussed
below. The request for increased base rates is based, in part, on investments
PEF is making in its generating fleet and in its transmission and distribution
systems. If approved by the FPSC, this portion of the new base rates would
increase residential bills by approximately $9.07 per 1,000 kWh, or 7.1 percent,
effective January 1, 2010. A ruling by the FPSC is expected in November 2009. We
cannot predict the outcome of this matter.




Included
within the base rate proposal is a request for an interim base rate increase of
$13 million. Additionally, on March 20, 2009, PEF petitioned the FPSC for a
limited proceeding to include in base rates revenue requirements of $63 million
for the repowered Bartow power plant, which is expected to begin commercial
operation in June 2009. If approved by the FPSC, PEF’s petitions for a combined
$76 million of new base rates would increase residential bills by approximately
$4.76 per 1,000 kWh, or 3.9 percent, effective July 1, 2009. On May 7, 2009, the
staff of the FPSC recommended that PEF be allowed to increase its base rates,
subject to refund, by a total of $70 million, effective the first
billing cycle 30 days following the commercial operation in-sevice date of
the repowered Bartow power plant.  However, a ruling by the FPSC
is expected later in May 2009. We cannot predict the outcome of this
matter.




FUEL
COST RECOVERY




On April
6, 2009, PEF received approval from the FPSC to reduce its 2009 fuel
cost-recovery factors by an amount sufficient to achieve a $206 million
reduction in fuel charges to retail customers as a result of effective fuel
purchasing strategies and lower fuel prices. The approval reduces residential
customers’ fuel charges by $6.90 per 1,000 kWh, or 5.0 percent, starting with
the first April 2009 billing cycle. Commercial and industrial customers will see
similar reductions.




In 2006,
Florida’s Office of Public Counsel (OPC) filed a petition with the FPSC asking
that the FPSC require PEF to refund to ratepayers $135 million, plus interest,
of alleged excessive past fuel recovery charges and sulfur dioxide (SO2) allowance
costs during the period 1996 to 2005. The OPC claimed that although Crystal
River Unit 4 and Crystal River Unit 5 (CR4 and CR5) were designed to burn a
blend of coals, PEF failed to act to lower ratepayers’ costs by purchasing the
most economical blends of coal. During the period specified in the petition,
PEF’s costs recovered through fuel recovery clauses were annually reviewed for
prudence and approval by the FPSC. On October 10, 2007, the FPSC issued its
order rejecting most of the OPC’s contentions. However, the FPSC found that PEF
had not been prudent in purchasing a portion of its coal requirements during the
period from 2003 to 2005. Accordingly, the FPSC ordered PEF to refund its
ratepayers $14 million, inclusive of interest, over a 12-month period beginning
January 1, 2008. The refund was returned to ratepayers through a reduction of
prior year under-recovered fuel costs. The FPSC also ordered PEF to address
whether it was prudent in its 2006 and 2007 coal purchases for CR4 and CR5. On
October 4, 2007, PEF filed a motion to establish a separate docket on the
prudence of its coal purchases for CR4 and CR5 for the years 2006 and 2007. On
October 17, 2007, the FPSC granted that motion. On February 2, 2009, the OPC
filed direct testimony in this hearing alleging that during 2006 and 2007, PEF
collected excessive fuel costs and SO2 allowance
costs of $61 million before interest. The OPC claimed that these excessive costs
were attributed to PEF’s ongoing practice of not blending the most economical
sources of coal at its CR4 and CR5 plants. A hearing on PEF’s 2006 and 2007 coal
purchases was held April 13-15, 2009. During the hearing, the OPC reduced the
alleged excessive fuel costs to $33 million before interest. We expect a
decision by the FPSC in June 2009. PEF believes its coal procurement practices
have been prudent. We cannot predict the outcome of this matter.




26




NUCLEAR
COST RECOVERY




On April
6, 2009, PEF received approval from the FPSC to defer until 2010 the recovery of
$198 million of nuclear preconstruction costs for PEF’s proposed nuclear plant
in Levy County, Florida (Levy), which the FPSC had authorized to be collected in
2009. The approval reduces residential customers’ nuclear cost-recovery charge
by $7.80 per
1,000 kWh, or 5.7 percent, starting with the first April 2009 billing cycle.
Commercial and industrial customers will see similar reductions.




On May 1,
2009, pursuant to the FPSC nuclear cost-recovery rule, PEF filed a petition to
recover $446 million of pre-construction and carrying costs incurred or
anticipated to be incurred during 2009 as well as the projected 2010 costs
associated with the Levy and CR3 uprate projects. In an effort to help mitigate
the initial price impact on its customers, as part of its filing, PEF has
proposed collecting certain costs over a five-year period, with associated
carrying costs. The deferral would result in a nuclear cost-recovery charge of
$6.69 per 1,000 kWh for residential customers, which is approximately half of
the amount PEF is eligible to recover in 2010 under the nuclear cost-recovery
rule. If approved, the charges would begin with the first January 2010 billing
cycle. The FPSC has scheduled hearings in this matter for September 8-11, 2009,
with a decision expected in October 2009. We cannot predict the outcome of this
matter.




OTHER MATTERS




On March
20, 2009, PEF filed a petition with the FPSC for expedited approval of the
deferral of $53 million in 2009 pension expenses and the authorization to charge
$33 million in estimated 2009 storm hardening expenses to its storm damage
reserve. The deferral of pension expense will not result in a change in PEF’s
2009 retail rates or prices, nor will charging storm hardening expenses to the
storm damage reserve. PEF requested that the deferral of pension expense
continue until the recovery of these costs is provided for in FPSC-approved base
rates. We cannot predict the outcome of this matter.







5.
            GOODWILL




We
account for goodwill in accordance with SFAS No. 142 “Goodwill and Other
Intangible Assets”, which requires that goodwill be tested for impairment at
least annually and more frequently when indicators of impairment exist. For our
utility segments, the goodwill impairment tests are performed at the utility
segment level. We performed the annual goodwill impairment tests for both the
PEC and PEF segments as of April 1, 2008, each of which indicated no impairment.
We are in the process of finalizing the annual goodwill impairment tests as of
April 1, 2009, for both the PEC and PEF segments. While these tests are not
fully completed, we do not believe the results of the tests will indicate any
impairment.




The
carrying amounts of goodwill at March 31, 2009 and December 31, 2008, for
reportable segments PEC and PEF, were $1.922 billion and $1.733 billion,
respectively. The amounts assigned to PEC and PEF are recorded in our Corporate
and Other business segment.







6.
            EQUITY AND
      COMPREHENSIVE INCOME




A.
            EARNINGS
      PER COMMON SHARE




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


Three
      Months Ended March 31,(in
      millions)
                        
                        2009
                        
                        
                        2008Weighted-average
      common shares – basic
                        
                        
                        277
                        
                        
                        
                        260Net
      effect of dilutive stock-based compensation plans
                        
                        
                        –
                        
                        
                        
                        –Weighted-average
      shares – fully dilutive
                        
                        
                        277
                        
                        
                        
                        260




27





B.  RECONCILIATION
OF TOTAL EQUITY




PROGRESS
ENERGY





The
consolidated financial statements include the accounts of Progress Energy and
its majority owned subsidiaries. Noncontrolling interests principally represent
minority shareholders’ proportionate share of the equity of our subsidiary,
Progress Telecom Holdings LLC and several variable interest entities (see Note
1C).




The
following table presents changes in total equity for the year to
date:





(in
      millions)
                                
                                Total
      Common Stock Equity
                                
                                
                                Noncontrolling
      Interests
                                
                                
                                Total
      EquityBalance,  December
      31, 2008
                                
                                $
                                8,687
                                
                                
                                $
                                6
                                
                                
                                $
                                8,693Net
      income
                                
                                
                                182
                                
                                
                                
                                1
                                
                                
                                
                                183Other
      comprehensive income
                                
                                
                                9
                                
                                
                                
                                –
                                
                                
                                
                                9Comprehensive
      income
                                
                                
                                
                                
                                
                                
                                
                                
                                
                                
                                192Issuance
      of shares through offerings and stock-based compensation plans (See Note
      6D)
                                
                                
                                565
                                
                                
                                
                                –
                                
                                
                                
                                565Dividends
      paid and declared
                                
                                
                                (182
                                )
                                
                                
                                –
                                
                                
                                
                                (182
                                )Distributions
      to noncontrolling interest
                                
                                
                                –
                                
                                
                                
                                (1
                                )
                                
                                
                                (1
                                )Balance,  March
      31, 2009
                                
                                $
                                9,261
                                
                                
                                $
                                6
                                
                                
                                $
                                9,267





(in
      millions)
                            
                            Total
      Common Stock Equity
                            
                            
                            Noncontrolling
      Interests
                            
                            
                            Total
      EquityBalance,  December
      31, 2007
                            
                            $
                            8,395
                            
                            
                            $
                            84
                            
                            
                            $
                            8,479Net
      income
                            
                            
                            209
                            
                            
                            
                            5
                            
                            
                            
                            214Other
      comprehensive loss
                            
                            
                            (8
                            )
                            
                            
                            –
                            
                            
                            
                            (8
                            )Comprehensive
      income
                            
                            
                            
                            
                            
                            
                            
                            
                            
                            
                            206Issuance
      of shares through offerings and stock-based compensation plans (See Note
      6D)
                            
                            
                            53
                            
                            
                            
                            –
                            
                            
                            
                            53Dividends
      paid and declared
                            
                            
                            (159
                            )
                            
                            
                            –
                            
                            
                            
                            (159
                            )Contributions
      from noncontrolling interest
                            
                            
                            
                            
                            
                            
                            2
                            
                            
                            
                            2Distributions
      to noncontrolling interest
                            
                            
                            –
                            
                            
                            
                            (85
                            )
                            
                            
                            (85
                            )Balance,  March
      31, 2008
                            
                            $
                            8,490
                            
                            
                            $
                            6
                            
                            
                            $
                            8,496





PEC





The
consolidated financial statements include the accounts of PEC and its majority
owned subsidiaries. Noncontrolling interests principally represent minority
shareholders’ proportionate share of the equity of several variable interest
entities (see Note 1C).




28





The
following table presents changes in total equity for the year to
date:




(in
      millions)
                                
                                Total
      Common Stock Equity
                                
                                
                                Noncontrolling
      Interests
                                
                                
                                Total
      EquityBalance,  December
      31, 2008
                                
                                $
                                4,301
                                
                                
                                $
                                4
                                
                                
                                $
                                4,305Net
      income
                                
                                
                                128
                                
                                
                                
                                –
                                
                                
                                
                                128Other
      comprehensive income
                                
                                
                                –
                                
                                
                                
                                –
                                
                                
                                
                                –Comprehensive
      income
                                
                                
                                
                                
                                
                                
                                
                                
                                
                                
                                128Issuance
      of shares through stock-based compensation plans
                                
                                
                                17
                                
                                
                                
                                –
                                
                                
                                
                                17Dividends
      paid to parent
                                
                                
                                (200
                                )
                                
                                
                                –
                                
                                
                                
                                (200
                                )Preferred
      stock dividends at stated rate
                                
                                
                                (1
                                )
                                
                                
                                –
                                
                                
                                
                                (1
                                )Tax
      benefit dividend
                                
                                
                                (1
                                )
                                
                                
                                –
                                
                                
                                
                                (1
                                )Balance,  March
      31, 2009
                                
                                $
                                4,244
                                
                                
                                $
                                4
                                
                                
                                $
                                4,248


(in
      millions)
                              
                              Total
      Common Stock Equity
                              
                              
                              Noncontrolling
      Interests
                              
                              
                              Total
      EquityBalance,  December
      31, 2007
                              
                              $
                              3,752
                              
                              
                              $
                              4
                              
                              
                              $
                              3,756Net
      income
                              
                              
                              123
                              
                              
                              
                              –
                              
                              
                              
                              123Other
      comprehensive loss
                              
                              
                              (5
                              )
                              
                              
                              –
                              
                              
                              
                              (5
                              )Comprehensive
      income
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              118Issuance
      of shares through stock-based compensation plans
                              
                              
                              29
                              
                              
                              
                              –
                              
                              
                              
                              29Preferred
      stock dividends at stated rate
                              
                              
                              (1
                              )
                              
                              
                              –
                              
                              
                              
                              (1
                              )Balance,  March
      31, 2008
                              
                              $
                              3,898
                              
                              
                              $
                              4
                              
                              
                              $
                              3,902





PEF




Interim
disclosures of changes in equity are required if the reporting entity has less
than wholly-owned subsidiaries, of which PEF has none. Therefore, an equity
reconciliation for PEF has not been provided.




29




C.  COMPREHENSIVE
INCOME




Progress
      EnergyThree
      Months Ended March 31,(in
      millions)
                      
                      2009
                      
                      
                      2008Net
      income
                      
                      $
                      183
                      
                      
                      $
                      214Other
      comprehensive income (loss)Reclassification
      adjustments included in net incomeChange
      in cash flow hedges (net of tax expense of $1 and $-,
      respectively)
                      
                      
                      1
                      
                      
                      
                      1Change
      in unrecognized items for pension and other postretirement benefits (net
      of tax expense of $-)
                      
                      
                      1
                      
                      
                      
                      –Net
      unrealized gains (losses) on cash flow hedges (net of tax (expense)
      benefit of $(4) and $6)
                      
                      
                      6
                      
                      
                      
                      (9
                      )Other
      (net of tax expense of $-)
                      
                      
                      1
                      
                      
                      
                      –Other
      comprehensive income (loss)
                      
                      
                      9
                      
                      
                      
                      (8
                      )Comprehensive
      income
                      
                      
                      192
                      
                      
                      
                      206Comprehensive
      income attributable to noncontrolling interests
                      
                      
                      (1
                      )
                      
                      
                      (5
                      )Comprehensive
      income attributable to controlling interests
                      
                      $
                      191
                      
                      
                      $
                      201





PECThree
      Months Ended March 31,(in
      millions)
                      
                      2009
                      
                      
                      2008Net
      income
                      
                      $
                      128
                      
                      
                      $
                      123Other
      comprehensive lossNet
      unrealized losses on cash flow hedges (net of tax benefit of
      $3)
                      
                      
                      –
                      
                      
                      
                      (5
                      )Other
      comprehensive loss
                      
                      
                      –
                      
                      
                      
                      (5
                      )Comprehensive
      income
                      
                      $
                      128
                      
                      
                      $
                      118





PEFThree
      Months Ended March 31,(in
      millions)
                      
                      2009
                      
                      
                      2008Net
      income
                      
                      $
                      89
                      
                      
                      $
                      67Other
      comprehensive lossNet
      unrealized losses on cash flow hedges (net of tax benefit of
      $3)
                      
                      
                      –
                      
                      
                      
                      (4
                      )Other
      comprehensive loss
                      
                      
                      –
                      
                      
                      
                      (4
                      )Comprehensive
      income
                      
                      $
                      89
                      
                      
                      $
                      63





D.  COMMON
STOCK




At
December 31, 2008, we had 500 million shares of common stock authorized under
our charter, of which approximately 264 million were outstanding. For the three
months ended March 31, 2009 and 2008, respectively, we issued approximately 15.5
million shares and 1.0 million shares of common stock resulting in approximately
$545 million and $20 million in net proceeds. Included in these amounts were
approximately 0.6 million shares and 0.4 million shares, respectively, for net
proceeds of approximately $22 million and $19 million, respectively, to meet the
requirements of the Progress Energy 401(k) Savings & Stock Ownership Plan
and the Investor Plus Stock Purchase Plan.




The 15.5
million shares disclosed above also included the Parent’s issuance of 14.4
million shares of common stock at a public offering price of $37.50 per share on
January 12, 2009. Net proceeds from this offering were $523 million. We used
$100 million of the proceeds to reduce the Parent’s revolving credit agreement
(RCA) borrowings and the remainder was used for general corporate
purposes.




30




7.
            PREFERRED STOCK OF
      SUBSIDIARIES




As
discussed in Note 10 in the 2008 Form 10-K, all of our preferred stock was
issued by the Utilities. The preferred stock is considered temporary equity due
to certain provisions that could require us to redeem the preferred stock for
cash. In the event of a default by PEC or PEF equivalent to the payment of four
quarterly dividends on the preferred stock, the holders of the preferred stock
are entitled to elect a majority of PEC or PEF’s respective Board of Directors
until all accrued and unpaid dividends are paid. All classes of preferred stock
are entitled to cumulative dividends with preference to the common stock
dividends, are redeemable by vote of the Utilities’ respective Board of
Directors at any time, and do not have any preemptive rights. All classes of
preferred stock have a liquidation preference equal to $100 per share plus any
accumulated unpaid dividends except for PEF’s 4.75%, $100 par value class which
does not have a liquidation preference. Each holder of PEC’s preferred stock is
entitled to one vote. Each holder of PEF’s preferred stock has no right to vote
except for certain circumstances regarding dividends payable on preferred stock
in default or potential changes to the preferred stock’s rights and
preferences.







8.
            DEBT AND CREDIT
      FACILITIES




Material
changes, if any, to Progress Energy’s, PEC’s and PEF’s debt and credit
facilities and financing activities since December 31, 2008, are as
follows.




On
January 15, 2009, PEC issued $600 million of First Mortgage Bonds, 5.30% Series
due 2019. A portion of the proceeds was used to repay the maturity of PEC’s $400
million 5.95% Senior Notes, due March 1, 2009. The remaining proceeds were used
to repay PEC’s outstanding short-term debt and for general corporate
purposes.




On
February 3, 2009, the Parent repaid $100 million of the $600 million outstanding
balance at December 31, 2008, borrowed under its RCA with proceeds from our 14.4
million share common stock issuance discussed in Note 6D. We will continue to
monitor the commercial paper and short-term credit markets to determine when to
repay the remaining $500 million outstanding balance of the RCA loan, while
maintaining an appropriate level of liquidity.




On March
19, 2009, the Parent issued an aggregate $750 million of Senior Notes consisting
of $300 million of 6.05% Senior Notes due 2014 and $450 million of 7.05% Senior
Notes due 2019. A portion of the proceeds was used to fund PEF’s capital
expenditures through an equity contribution. The remaining proceeds will be used
for general corporate purposes.







9.
            FAIR VALUE
      MEASUREMENTS




We
implemented SFAS No. 157 as of January 1, 2008, for all recurring financial
assets and liabilities. The adoption of SFAS No. 157 for recurring financial
assets and liabilities did not have a material impact on our or the Utilities'
financial position or results of operations. We utilized the deferral provision
of FSP FAS 157-2 for all nonrecurring nonfinancial assets and liabilities
within its scope. Major categories of our assets and liabilities to which the
deferral applied included reporting units and long-lived asset groups measured
at fair value for impairment purposes, asset retirement obligations initially
recognized at fair value, and nonfinancial liabilities for exit and disposal
costs and indemnifications initially measured at fair value. During the quarter
ended March 31, 2009, neither our or the Utilities’ nonfinancial assets or
liabilities were subject to remeasurement. Therefore, the adoption of FSP FAS
157-2 did not have a material impact on our or the Utilities’ financial position
or results of operations.




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




SFAS No.
157 establishes a fair value hierarchy that prioritizes the inputs used to
measure fair value, and requires fair value measurements to be categorized based
on the observability of those inputs. The hierarchy gives the highest priority
to unadjusted quoted prices in active markets for identical assets or
liabilities (Level 1 inputs) and the lowest




31




priority
to unobservable inputs (Level 3 inputs). The three levels of the fair value
hierarchy defined by SFAS No. 157 are as follows:




Level 1 –
The pricing inputs are unadjusted quoted prices in active markets for identical
assets or liabilities as of the reporting date. Active markets are those in
which transactions for the asset or liability occur in sufficient frequency and
volume to provide pricing information on an ongoing basis. Level 1 primarily
consists of financial instruments such as exchange-traded derivatives and listed
equities.




Level 2 –
The pricing inputs are inputs other than quoted prices included within Level 1
that are observable for the asset or liability, either directly or indirectly.
Level 2 includes those financial instruments that are valued using models or
other valuation methodologies. These models are primarily industry-standard
models that consider various assumptions, including quoted forward prices for
commodities, time value, volatility factors, and current market and contractual
prices for the underlying instruments, as well as other relevant economic
measures. Substantially all of these assumptions are observable in the
marketplace throughout the full term of the instrument, can be derived from
observable data or are supported by observable levels at which transactions are
executed in the marketplace. Instruments in this category include
non-exchange-traded derivatives such as over-the-counter forwards, swaps and
options, certain marketable debt securities, and financial instruments traded in
less than active markets.




Level 3 –
The pricing inputs include significant inputs that are generally less observable
from objective sources. These inputs may be used with internally developed
methodologies that result in management’s best estimate of fair value. Level 3
instruments may include longer-term instruments that extend into periods where
quoted prices or other observable inputs are not available.




The
following tables set forth by level within the fair value hierarchy our and the
Utilities’ financial assets and liabilities that were accounted for at fair
value on a recurring basis at March 31, 2009. As required by SFAS No. 157,
financial assets and liabilities are classified in their entirety based on the
lowest level of input that is significant to the fair value measurement. Our
assessment of the significance of a particular input to the fair value
measurement requires judgment, and may affect the valuation of fair value assets
and liabilities and their placement within the fair value hierarchy
levels.




Progress
      Energy(in
      millions)
                  
                  Level
      1
                  
                  
                  Level
      2
                  
                  
                  Level
      3
                  
                  
                  TotalAssets:Commodity
      derivatives
                  
                  $
                  –
                  
                  
                  $
                  5
                  
                  
                  $
                  –
                  
                  
                  $
                  5Nuclear
      decommissioning trust funds
                  
                  
                  621
                  
                  
                  
                  423
                  
                  
                  
                  –
                  
                  
                  
                  1,044Other
      marketable securities
                  
                  
                  25
                  
                  
                  
                  39
                  
                  
                  
                  –
                  
                  
                  
                  64Total
      assets
                  
                  $
                  646
                  
                  
                  $
                  467
                  
                  
                  $
                  –
                  
                  
                  $
                  1,113Liabilities:Commodity
      derivatives
                  
                  $
                  –
                  
                  
                  $
                  (858
                  )
                  
                  $
                  (43
                  )
                  
                  $
                  (901
                  )CVO
      derivatives
                  
                  
                  –
                  
                  
                  
                  (27
                  )
                  
                  
                  –
                  
                  
                  
                  (27
                  )Total
      liabilities
                  
                  $
                  –
                  
                  
                  $
                  (885
                  )
                  
                  $
                  (43
                  )
                  
                  $
                  (928
                  )




PEC(in
      millions)
                    
                    Level
      1
                    
                    
                    Level
      2
                    
                    
                    Level
      3
                    
                    
                    TotalAssets:Interest
      rate derivatives
                    
                    $
                    –
                    
                    
                    $
                    1
                    
                    
                    $
                    –
                    
                    
                    $
                    1Nuclear
      decommissioning trust funds
                    
                    
                    422
                    
                    
                    
                    229
                    
                    
                    
                    –
                    
                    
                    
                    651Other
      marketable securities
                    
                    
                    8
                    
                    
                    
                    –
                    
                    
                    
                    –
                    
                    
                    
                    8Total
      assets
                    
                    $
                    430
                    
                    
                    $
                    230
                    
                    
                    $
                    –
                    
                    
                    $
                    660Liabilities:Commodity
      derivatives
                    
                    $
                    –
                    
                    
                    $
                    (107
                    )
                    
                    $
                    (23
                    )
                    
                    $
                    (130
                    )






32




PEF(in
      millions)
                  
                  Level
      1
                  
                  
                  Level
      2
                  
                  
                  Level
      3
                  
                  
                  TotalAssets:Commodity
      derivatives
                  
                  $
                  –
                  
                  
                  $
                  5
                  
                  
                  $
                  –
                  
                  
                  $
                  5Nuclear
      decommissioning trust funds
                  
                  
                  199
                  
                  
                  
                  194
                  
                  
                  
                  –
                  
                  
                  
                  393Total
      assets
                  
                  $
                  199
                  
                  
                  $
                  199
                  
                  
                  $
                  –
                  
                  
                  $
                  398Liabilities:Commodity
      derivatives
                  
                  $
                  –
                  
                  
                  $
                  (751
                  )
                  
                  $
                  (20
                  )
                  
                  $
                  (771
                  )





The
determination of the fair values above incorporates various factors required
under SFAS No. 157, including risks of nonperformance by us or our
counterparties. Such risks consider not only the credit standing of the
counterparties involved and the impact of credit enhancements (such as cash
deposits or letters of credit), but also the impact of our and the Utilities’
credit risk on our liabilities.




Commodity
and interest rate derivatives reflect positions held by us and the Utilities.
Most over-the-counter commodity and interest rate derivatives are valued using
financial models which utilize observable inputs for similar instruments and are
classified within Level 2. Other derivatives are valued utilizing inputs that
are not observable for substantially the full term of the contract, or for which
the impact of the unobservable period is significant to the fair value of the
derivative. Such derivatives are classified within Level 3. See Note 11 for
discussion of risk management activities and derivative
transactions.




Nuclear
decommissioning trust funds reflect the assets of the Utilities’ nuclear
decommissioning trusts, as discussed in Note 13 of the 2008 Form 10-K. The
assets of the trusts are invested primarily in exchange-traded equity securities
(classified within Level 1) and marketable debt securities, most of which are
valued using Level 1 inputs for similar instruments, and are classified within
Level 2.




Other
marketable securities represent available-for-sale debt and equity securities
used to fund certain employee benefit costs.




We issued
Contingent Value Obligations (CVOs) in connection with the acquisition of
Florida Progress Corporation (Florida Progress), as discussed in Note 15 in the
2008 Form 10-K. The CVOs are derivatives recorded at fair value based on quoted
prices from a less than active market and are classified as Level
2.




33




The
following tables set forth a reconciliation of changes in the fair value of our
and the Utilities’ commodity derivatives classified as Level 3 in the fair value
hierarchy.




Progress
      Energy(in
      millions)
                
                2009
                
                
                2008Derivatives,
      net at January 1
                
                $
                (41
                )
                
                $
                26Total
      gains (losses), realized and unrealized:Included
      in earnings
                
                
                –
                
                
                
                –Included
      in other comprehensive income
                
                
                –
                
                
                
                –Deferred
      as regulatory assets and liabilities, net
                
                
                (2
                )
                
                
                29Purchases,
      issuances and settlements, net
                
                
                –
                
                
                
                –Transfers
      in (out) of Level 3, net
                
                
                –
                
                
                
                –Derivatives,
      net at March 31
                
                $
                (43
                )
                
                $
                55





PEC(in
      millions)
                
                2009
                
                
                2008Derivatives,
      net at January 1
                
                $
                (22
                )
                
                $
                6Total
      gains (losses), realized and unrealized:Included
      in earnings
                
                
                –
                
                
                
                –Included
      in other comprehensive income
                
                
                –
                
                
                
                –Deferred
      as regulatory assets and liabilities, net
                
                
                (1
                )
                
                
                6Purchases,
      issuances and settlements, net
                
                
                –
                
                
                
                –Transfers
      in (out) of Level 3, net
                
                
                –
                
                
                
                –Derivatives,
      net at March 31
                
                $
                (23
                )
                
                $
                12





PEF(in
      millions)
                
                2009
                
                
                2008Derivatives,
      net at January 1
                
                $
                (19
                )
                
                $
                20Total
      gains (losses), realized and unrealized:Included
      in earnings
                
                
                –
                
                
                
                –Included
      in other comprehensive income
                
                
                –
                
                
                
                –Deferred
      as regulatory assets and liabilities, net
                
                
                (1
                )
                
                
                23Purchases,
      issuances and settlements, net
                
                
                –
                
                
                
                –Transfers
      in (out) of Level 3, net
                
                
                –
                
                
                
                –Derivatives,
      net at March 31
                
                $
                (20
                )
                
                $
                43





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





Transfers
in (out) of Level 3 represent existing assets or liabilities that were either
previously categorized as a higher level for which the inputs to the model
became unobservable or assets and liabilities that were previously classified as
Level 3 for which the lowest significant input became observable during the
period. There were no transfers into or out of Level 3 during the periods ended
March 31, 2009 and 2008.







10.
            BENEFIT
      PLANS




We have
noncontributory defined benefit retirement plans that provide pension benefits
for substantially all full-time employees. We also have supplementary defined
benefit pension plans that provide benefits to higher-level employees. In
addition to pension benefits, we provide contributory other postretirement
benefits (OPEB), including certain health care and life insurance benefits, for
retired employees who meet specified criteria.




34




The
components of the net periodic benefit cost for the respective Progress
Registrants for the three months ended March 31 were:




Progress
      EnergyPension
      Benefits
                  
                  
                  Other Postretirement Benefits(in
      millions)
                  
                  2009
                  
                  
                  2008
                  
                  
                  2009
                  
                  
                  2008Service
      cost
                  
                  $
                  10
                  
                  
                  $
                  12
                  
                  
                  $
                  2
                  
                  
                  $
                  2Interest
      cost
                  
                  
                  34
                  
                  
                  
                  31
                  
                  
                  
                  9
                  
                  
                  
                  8Expected
      return on plan assets
                  
                  
                  (35
                  )
                  
                  
                  (41
                  )
                  
                  
                  (1
                  )
                  
                  
                  (2
                  )Amortization
      of actuarial loss (a)
                  
                  
                  12
                  
                  
                  
                  3
                  
                  
                  
                  1
                  
                  
                  
                  1Other
      amortization, net (a)
                  
                  
                  2
                  
                  
                  
                  –
                  
                  
                  
                  1
                  
                  
                  
                  1Net
      periodic cost
                  
                  $
                  23
                  
                  
                  $
                  5
                  
                  
                  $
                  12
                  
                  
                  $
                  10





(a)      Adjusted
to reflect PEF’s rate treatment. See Note 16B in the 2008 Form
10-K.





PECPension
      Benefits
                    
                    
                    Other Postretirement Benefits(in
      millions)
                    
                    2009
                    
                    
                    2008
                    
                    
                    2009
                    
                    
                    2008Service
      cost
                    
                    $
                    4
                    
                    
                    $
                    6
                    
                    
                    $
                    1
                    
                    
                    $
                    1Interest
      cost
                    
                    
                    16
                    
                    
                    
                    14
                    
                    
                    
                    5
                    
                    
                    
                    4Expected
      return on plan assets
                    
                    
                    (17
                    )
                    
                    
                    (16
                    )
                    
                    
                    (1
                    )
                    
                    
                    (1
                    )Amortization
      of actuarial loss
                    
                    
                    2
                    
                    
                    
                    2
                    
                    
                    
                    1
                    
                    
                    
                    –Other
      amortization, net
                    
                    
                    1
                    
                    
                    
                    –
                    
                    
                    
                    –
                    
                    
                    
                    –Net
      periodic cost
                    
                    $
                    6
                    
                    
                    $
                    6
                    
                    
                    $
                    6
                    
                    
                    $
                    4





PEFPension
      Benefits
                  
                  
                  Other Postretirement Benefits(in
      millions)
                  
                  2009
                  
                  
                  2008
                  
                  
                  2009
                  
                  
                  2008Service
      cost
                  
                  $
                  5
                  
                  
                  $
                  4
                  
                  
                  $
                  1
                  
                  
                  $
                  1Interest
      cost
                  
                  
                  14
                  
                  
                  
                  13
                  
                  
                  
                  3
                  
                  
                  
                  3Expected
      return on plan assets
                  
                  
                  (15
                  )
                  
                  
                  (21
                  )
                  
                  
                  –
                  
                  
                  
                  –Amortization
      of actuarial loss
                  
                  
                  9
                  
                  
                  
                  –
                  
                  
                  
                  –
                  
                  
                  
                  –Other
      amortization, net
                  
                  
                  –
                  
                  
                  
                  –
                  
                  
                  
                  1
                  
                  
                  
                  1Net
      periodic cost (benefit)
                  
                  $
                  13
                  
                  
                  $
                  (4
                  )
                  
                  $
                  5
                  
                  
                  $
                  5





In 2009,
contributions directly to pension plan assets are expected to approximate $222
million for us, $164 million for PEC and $57 million for PEF. An immaterial
amount was contributed during the three months ended March 31,
2009.







11.
            RISK MANAGEMENT
      ACTIVITIES AND DERIVATIVE
TRANSACTIONS




We are
exposed to various risks related to changes in market conditions. We have a risk
management committee that includes senior executives from various business
groups. The risk management committee is responsible for administering risk
management policies and monitoring compliance with those policies by all
subsidiaries. Under our risk policy, we may use a variety of instruments,
including swaps, options and forward contracts, to manage exposure to
fluctuations in commodity prices and interest rates. Such instruments contain
credit risk if the counterparty fails to perform under the contract. We minimize
such risk by performing credit and financial reviews using a combination of
financial analysis and publicly available credit ratings of such counterparties.
Potential nonperformance by counterparties is not expected to have a material
effect on our financial position or results of operations.




35




A.      COMMODITY
DERIVATIVES




GENERAL




Most of
our physical commodity contracts are not derivatives or qualify as normal
purchases or sales pursuant to SFAS No. 133, “Accounting for Derivative
Instruments and Hedging Activities” (SFAS No. 133). Therefore, such contracts
are not recorded at fair value.




ECONOMIC
DERIVATIVES




Derivative
products, primarily natural gas and oil contracts, may be entered into from time
to time for economic hedging purposes. While management believes the economic
hedges mitigate exposures to fluctuations in commodity prices, these instruments
are not designated as hedges for accounting purposes and are monitored
consistent with trading positions.




The
Utilities have derivative instruments related to their exposure to price
fluctuations on fuel oil and natural gas purchases. Substantially all of these
instruments receive regulatory accounting treatment. Related unrealized gains
and losses are recorded in regulatory liabilities and regulatory assets,
respectively, on the Balance Sheets until the contracts are settled. After
settlement of the derivatives and the fuel is consumed, any realized gains or
losses are passed through the fuel cost-recovery clause.




Certain
hedge agreements may result in the receipt of, or posting of, derivative
collateral with our counterparties, depending on the daily derivative position.
Fluctuations in commodity prices that lead to our return of collateral received
and/or our posting of collateral with our counterparties negatively impact our
liquidity. We manage open positions with strict policies that limit our exposure
to market risk and require daily reporting to management of potential financial
exposures.




Certain
counterparties have posted or held cash collateral in support of these
instruments. PEC had a cash collateral asset included in prepayments and other
current assets of $28 million and $18 million on the PEC Consolidated Balance
Sheet at March 31, 2009 and December 31, 2008, respectively. At March 31, 2009,
PEC had 61.4 million MMBtu notional of natural gas related to outstanding
commodity derivative swaps that were entered into to hedge forecasted natural
gas purchases. Due to the significant decline in natural gas prices since
December 31, 2008, PEF's cash collateral asset included in derivative collateral
posted was $535 million and $335 million on the PEF Balance Sheet at March 31,
2009 and December 31, 2008, respectively. At March 31, 2009, PEF had 263.8
million MMBtu notional of natural gas and 3.5 million barrels notional of oil
related to outstanding commodity derivative swaps that were entered into to
hedge forecasted oil and natural gas purchases.




CASH
FLOW HEDGES




The
Utilities designate a portion of commodity derivative instruments as cash flow
hedges under SFAS No. 133. From time to time we hedge exposure to market risk
associated with fluctuations in the price of power for our forecasted sales.
Realized gains and losses are recorded net in operating revenues. We also hedge
exposure to market risk associated with fluctuations in the price of fuel for
fleet vehicles. At March 31, 2009, we had 0.7 million gallons notional of
gasoline and 0.6 million gallons notional of diesel related to outstanding
commodity derivative swaps at each of PEC and PEF that were entered into to
hedge forecasted gasoline and diesel purchases. Realized gains and losses are
recorded net as part of fleet vehicle fuel costs. At March 31, 2009 and December
31, 2008, neither we nor the Utilities had material outstanding positions in
such contracts. The ineffective portion of commodity cash flow hedges was not
material to our or the Utilities’ results of operations for the three months
ended March 31, 2009 and 2008.




At March
31, 2009 and December 31, 2008, the amount recorded in our or the Utilities’
accumulated other comprehensive income related to commodity cash flow hedges was
not material.




B.      INTEREST
RATE DERIVATIVES – FAIR VALUE OR CASH FLOW HEDGES




We use
cash flow hedging strategies to reduce exposure to changes in cash flow due to
fluctuating interest rates. We use fair value hedging strategies to reduce
exposure to changes in fair value due to interest rate changes. The notional
amounts of interest rate derivatives are not exchanged and do not represent
exposure to credit loss. In the




36




event of
default by the counterparty, the exposure in these transactions is the cost of
replacing the agreements at current market rates.




CASH
FLOW HEDGES




At March
31, 2009, all open interest rate hedges will reach their mandatory termination
dates within three and a half years. It is expected that in the next twelve
months $3 million and $4 million, net of tax, primarily related to terminated
hedges, will be reclassified to interest expense at the Parent and PEC,
respectively. The actual amounts that will be reclassified to earnings may vary
from the expected amounts as a result of changes in interest rates and changes
in the timing of debt issuances.





At
December 31, 2008, the Parent had $200 million notional of interest rate cash
flow hedges. All of these forward starting swaps were terminated on March 16,
2009, in conjunction with the Parent’s issuance of $450 million of 7.05% Senior
Notes due 2019. In January 2009, the Parent entered into a $50 million notional
forward starting swap to mitigate exposure to interest rate risk in anticipation
of future debt issuances. At March 31, 2009, the Parent had $50 million notional
of interest rate cash flow hedges.




At
December 31, 2008, PEC had $250 million notional of interest rate cash flow
hedges. All of these forward starting swaps were terminated on January 8, 2009,
in conjunction with PEC’s issuance of $600 million First Mortgage Bonds 5.30%
Series due 2019. In January 2009, PEC entered into a $50 million notional
forward starting swap to mitigate exposure to interest rate risk in anticipation
of future debt issuances. At March 31, 2009, PEC had $50 million notional of
interest rate cash flow hedges.




At
December 31, 2008, PEF had no outstanding interest rate cash flow hedges. In
January 2009, PEF entered into a $50 million notional forward starting swap to
mitigate exposure to interest rate risk in anticipation of future debt
issuances. At March 31, 2009, PEF had $50 million notional of interest rate cash
flow hedges.





FAIR
VALUE HEDGES




For
interest rate fair value hedges, the change in the fair value of the hedging
derivative is recorded in net interest charges and is offset by the change in
the fair value of the hedged item. At March 31, 2009, and December 31, 2008,
neither we nor the Utilities had any outstanding positions in such
contracts.




C.      CONTINGENT
FEATURES




Certain
of our derivative instruments contain provisions that require our debt to
maintain an investment grade credit rating from each of the major credit rating
agencies. If our debt were to fall below investment grade, it would be in
violation of these provisions, and the counterparties to the derivative
instruments could request immediate payment or demand immediate and ongoing full
overnight collateralization on derivative instruments in net liability
positions.




The
aggregate fair value of all derivative instruments at PEC with credit
risk-related contingent features that are in a liability position at March 31,
2009 is $130 million, for which PEC has posted collateral of $28 million in the
normal course of business. If the credit risk-related contingent features
underlying these agreements were triggered at March 31, 2009, PEC would have
been required to post an additional $102 million of collateral with its
counterparties.




The
aggregate fair value of all derivative instruments at PEF with credit
risk-related contingent features that are in a liability position at March 31,
2009 is $771 million, for which PEF has posted collateral of $535 million in the
normal course of business. If the credit risk-related contingent features
underlying these agreements were triggered on March 31, 2009, PEF
would have been required to post an additional $231 million of
collateral with its counterparties.




37




D.      DERIVATIVE
INSTRUMENT AND HEDGING ACTIVITY INFORMATION





Progress
Energy





The
following table presents the fair value of derivative instruments at March 31,
2009 and December 31, 2008:




(in
      millions)
                          
                          March
      31, 2009
                          
                          
                          December
      31, 2008Instrument
      / Balance sheet location
                          
                          Asset
                          
                          
                          Liability
                          
                          
                          Asset
                          
                          
                          LiabilityDerivatives
      designated as hedging instruments under SFAS No. 133Commodity
      cash flow derivativesDerivative
      liabilities, current
                          
                          
                          
                          
                          $
                          (1
                          )
                          
                          
                          
                          
                          $
                          (2
                          )Interest
      rate derivativesDerivative
      liabilities, current
                          
                          
                          
                          
                          
                          –
                          
                          
                          
                          
                          
                          
                          (65
                          )Total
      derivatives designated as hedging instruments under SFAS No.
      133
                          
                          
                          
                          
                          
                          (1
                          )
                          
                          
                          
                          
                          
                          (67
                          )Derivatives
      not designated as hedging instruments under SFAS No. 133Commodity
      derivatives(a)Prepayments
      and other current assets
                          
                          $
                          5
                          
                          
                          
                          
                          
                          
                          $
                          9Other
      assets and deferred debits
                          
                          
                          –
                          
                          
                          
                          
                          
                          
                          
                          1Derivative
      liabilities, current
                          
                          
                          
                          
                          
                          
                          (553
                          )
                          
                          
                          
                          
                          
                          
                          (425
                          )Derivative
      liabilities, long-term
                          
                          
                          
                          
                          
                          
                          (347
                          )
                          
                          
                          
                          
                          
                          
                          (263
                          )CVOs(c)Other
      liabilities and deferred credits
                          
                          
                          
                          
                          
                          
                          (27
                          )
                          
                          
                          
                          
                          
                          
                          (34
                          )Fair
      value of derivatives not designated as hedging instruments under SFAS No.
      133
                          
                          
                          5
                          
                          
                          
                          (927
                          )
                          
                          
                          10
                          
                          
                          
                          (722
                          )DIG
      Issue C20(b)Derivative
      liabilities, current
                          
                          
                          
                          
                          
                          
                          (2
                          )
                          
                          
                          
                          
                          
                          
                          (1
                          )Derivative
      liabilities, long-term
                          
                          
                          
                          
                          
                          
                          (5
                          )
                          
                          
                          
                          
                          
                          
                          (6
                          )Total
      derivatives not designated as hedging instruments under SFAS No.
      133
                          
                          
                          5
                          
                          
                          
                          (934
                          )
                          
                          
                          10
                          
                          
                          
                          (729
                          )Total
      derivatives
                          
                          $
                          5
                          
                          
                          $
                          (935
                          )
                          
                          $
                          10
                          
                          
                          $
                          (796
                          )





(a)
            Substantially
      all of these contracts receive regulatory
  treatment.


(b)
            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 13).


(c)
            As
      discussed in Note 15 of the 2008 Form 10-K, the Parent issued 98.6 million
      CVOs in connection with the acquisition of Florida Progress during
      2000.




38




The
following tables present the effect of derivative instruments on other
comprehensive income (OCI) (See Note 6C) and the Consolidated Statements of
Income for the three months ended March 31, 2009 and 2008:




Derivatives
      Designated as Hedging Instruments under SFAS No. 133Instrument
                            
                            Amount
      of Gain or (Loss) Recognized in OCI, Net of Tax on Derivatives(a)
                            
                            Location
      of Gain or (Loss) Reclassified from Accumulated OCI into Income(a)
                            
                            Amount
      of Gain or (Loss), Net of Tax Reclassified from Accumulated OCI into
      Income(a)
                            
                            Location
      of Gain or (Loss) Recognized in Income on Derivatives(b)
                            
                            Amount
      of Pre-tax Gain or (Loss) Recognized in Income on Derivatives(b)(in
      millions)
                            
                            2009
                            
                            
                            2008
                            
                            
                            
                            2009
                            
                            
                            2008
                            
                            
                            
                            2009
                            
                            
                            2008Commodity
      cash flow
                              derivatives
                            
                            $
                            –
                            
                            
                            $
                            (2
                            )
                            
                            
                            $
                            –
                            
                            
                            $
                            –
                            
                            
                            
                            $
                            –
                            
                            
                            $
                            –Interest
      rate derivatives(c)
                            
                            
                            6
                            
                            
                            
                            (7
                            )
                            Interest
      charges
                            
                            
                            (1
                            )
                            
                            
                            (1
                            )
                            Interest
      charges
                            
                            
                            (3
                            )
                            
                            
                            –Total
                            
                            $
                            6
                            
                            
                            $
                            (9
                            )
                            
                            
                            $
                            (1
                            )
                            
                            $
                            (1
                            )
                            
                            
                            $
                            (3
                            )
                            
                            $
                            –




(a)
              Effective
      portion.
 (b)
              Related
      to ineffective portion and amount excluded from effectiveness
      testing.
 (c)
              Amounts
      in accumulated other comprehensive income related to terminated hedges are
      reclassified to earnings as the interest expense is recorded.  The
      effective portion of the hedges will be amortized to interest expense over
      the term of the related debt.






Derivatives
      Not Designated as Hedging Instruments under SFAS No.
133Instrument
                                                                        
                                                                        Realized Gain or (Loss)(a)
                                                                        
                                                                        
                                                                        Unrealized Gain or (Loss)(b)(in
      millions)
                                                                        
                                                                        2009
                                                                        
                                                                        
                                                                        2008
                                                                        
                                                                        
                                                                        2009
                                                                        
                                                                        
                                                                        2008Commodity
      derivatives
                                                                        
                                                                        $
                                                                        (127
                                                                        )
                                                                        
                                                                        $
                                                                        16
                                                                        
                                                                        
                                                                        $
                                                                        (95
                                                                        )
                                                                        
                                                                        $
                                                                        245




(a)
              After
      settlement of the derivaties and the fuel is consumed, gains or losses are
      passed through the fuel cost-recovery
clause.
 (b)
              Amounts
      are recorded in regulatory liabilities and assets, respectively, on the
      Balance Sheets until derivatives are
settled.




Instrument
                Location
      of Gain or (Loss) Recognized in Income on Derivatives
                
                Amount
      of Gain or (Loss) Recognized in Income on Derivatives(in
      millions)
                
                
                2009
                
                
                2008Commodity
      derivatives
                Other,
      net
                
                $
                (1
                )
                
                $
                –DIG
      Issue C20
                Other,
      net
                
                
                –
                
                
                
                1CVOs
                Other,
      net
                
                
                7
                
                
                
                –Total
                
                
                $
                6
                
                
                $
                1




39




PEC




The
following table presents the fair value of derivative instruments at March 31,
2009 and December 31, 2008:




(in
      millions)
                    
                    March
      31, 2009
                    
                    
                    December
      31, 2008Instrument
      / Balance sheet location
                    
                    Asset
                    
                    
                    Liability
                    
                    
                    Asset
                    
                    
                    LiabilityDerivatives
      designated as hedging instruments under SFAS No. 133Commodity
      cash flow derivativesDerivative
      liabilities, current
                    
                    
                    
                    
                    $
                    (1
                    )
                    
                    
                    
                    
                    $
                    (1
                    )Interest
      rate derivativesPrepayments
      and other current assets
                    
                    $
                    1
                    
                    
                    
                    
                    
                    
                    $
                    –Derivative
      liabilities, current
                    
                    
                    
                    
                    
                    
                    –
                    
                    
                    
                    
                    
                    
                    
                    (35
                    )Total
      derivatives designated as hedging instruments under SFAS No.
      133
                    
                    
                    1
                    
                    
                    
                    (1
                    )
                    
                    
                    –
                    
                    
                    
                    (36
                    )Derivatives
      not designated as hedging instruments under SFAS No. 133Commodity
      derivatives(a)Derivative
      liabilities, current
                    
                    
                    
                    
                    
                    
                    (57
                    )
                    
                    
                    
                    
                    
                    
                    (45
                    )Other
      liabilities and deferred credits
                    
                    
                    
                    
                    
                    
                    (72
                    )
                    
                    
                    
                    
                    
                    
                    (54
                    )Fair
      value of derivatives not designated as hedging instruments under SFAS No.
      133
                    
                    
                    
                    
                    
                    
                    (129
                    )
                    
                    
                    
                    
                    
                    
                    (99
                    )DIG
      Issue C20(b)Derivative
      liabilities, current
                    
                    
                    
                    
                    
                    
                    (2
                    )
                    
                    
                    
                    
                    
                    
                    (1
                    )Other
      liabilities and deferred credits
                    
                    
                    
                    
                    
                    
                    (5
                    )
                    
                    
                    
                    
                    
                    
                    (6
                    )Total
      derivatives not designated as hedging instruments under SFAS No.
      133
                    
                    
                    –
                    
                    
                    
                    (136
                    )
                    
                    
                    –
                    
                    
                    
                    (106
                    )Total
      derivatives
                    
                    $
                    1
                    
                    
                    $
                    (137
                    )
                    
                    $
                    –
                    
                    
                    $
                    (142
                    )





(a)
            Substantially
      all of these contracts receive regulatory
  treatment.


(b)
            In
      2003, PEC recorded a $38 million pre-tax ($23 million after-tax) fair
      value loss transition adjustment pursuant to the provisions of DIG Issue
      C20. The related liability is being amortized to earnings over the term of
      the related contract (See Note
13).


40




The
following tables present the effect of derivative instruments on OCI (See Note
6C) and the Consolidated Statements of Income for the three months ended March
31, 2009 and 2008:




Derivatives
      Designated as Hedging Instruments under SFAS No. 133Instrument
                          
                          Amount
      of Gain or (Loss) Recognized in OCI, Net of Tax on Derivatives(a)
                          
                          Location
      of Gain or (Loss) Reclassified from Accumulated OCI into Income(a)
                          
                          Amount
      of Gain or (Loss), Net of Tax Reclassified from Accumulated OCI into
      Income(a)
                          
                          Location
      of Gain or (Loss) Recognized in Income on Derivatives(b)
                          
                          Amount
      of Pre-tax Gain or (Loss) Recognized in Income on Derivatives(b)(in
      millions)
                          
                          2009
                          
                          
                          2008
                          
                          
                          
                          2009
                          
                          
                          2008
                          
                          
                          
                          2009
                          
                          
                          2008Commodity
      cash flow
                            derivatives
                          
                          $
                          –
                          
                          
                          $
                          (2
                          )
                          
                          
                          $
                          –
                          
                          
                          $
                          –
                          
                          
                          
                          $
                          –
                          
                          
                          $
                          –Interest
      rate derivatives(c)
                          
                          
                          –
                          
                          
                          
                          (3
                          )
                          Interest
      charges
                          
                          
                          –
                          
                          
                          
                          –
                          
                          Interest
      charges
                          
                          
                          (2
                          )
                          
                          
                          –Total
                          
                          $
                          –
                          
                          
                          $
                          (5
                          )
                          
                          
                          $
                          –
                          
                          
                          $
                          –
                          
                          
                          
                          $
                          (2
                          )
                          
                          $
                          –




(a)
            Effective
      portion. (b)
              Related
      to ineffective portion and amount excluded from effectiveness
      testing.
 (c)
              Amounts
      in accumulated other comprehensive income related to terminated hedges are
      reclassified to earnings as the interest expense is recorded.  The
      effective portion of the hedges will be amortized to interest expense over
      the term of the related debt.




Derivatives
      Not Designated as Hedging Instruments under SFAS No.
    133Instrument
                          
                          Realized Gain or (Loss)(a)
                          
                          
                          Unrealized Gain or (Loss)(b)(in
      millions)
                          
                          2009
                          
                          
                          2008
                          
                          
                          2009
                          
                          
                          2008Commodity
      derivatives
                          
                          $
                          (18
                          )
                          
                          $
                          –
                          
                          
                          $
                          (11
                          )
                          
                          $
                          31




(a)
            After
      settlement of the derivaties and the fuel is consumed, gains or losses are
      passed through the fuel cost-recovery
clause. (b)
              Amounts
      are recorded in regulatory liabilities and assets, respectively, on the
      Balance Sheets until derivatives are
settled.


Instrument
                  Location
      of Gain or (Loss) Recognized in Income on Derivatives
                  
                  Amount
      of Gain or (Loss) Recognized in Income on Derivatives(in
      millions)
                  
                  
                  2009
                  
                  
                  2008Commodity
      derivatives
                  Other,
      net
                  
                  $
                  (1
                  )
                  
                  $
                  –DIG
      Issue C20
                  Other,
      net
                  
                  
                  –
                  
                  
                  
                  1Total
                  
                  
                  $
                  (1
                  )
                  
                  $
                  1


41




PEF




The
following table presents the fair value of derivative instruments at March 31,
2009 and December 31, 2008:




(in
      millions)
                    
                    March
      31, 2009
                    
                    
                    December
      31, 2008Instrument
      / Balance sheet location
                    
                    Asset
                    
                    
                    Liability
                    
                    
                    Asset
                    
                    
                    LiabilityDerivatives
      not designated as hedging instruments under SFAS No. 133Commodity
      derivatives(a)Prepayments
      and other current assets
                    
                    $
                    5
                    
                    
                    
                    
                    
                    $
                    9Other
      assets and deferred debits
                    
                    
                    –
                    
                    
                    
                    
                    
                    
                    1Derivative
      liabilities, current
                    
                    
                    
                    
                    
                    $
                    (496
                    )
                    
                    
                    
                    
                    
                    $
                    (380
                    )Derivative
      liabilities, long-term
                    
                    
                    
                    
                    
                    
                    (275
                    )
                    
                    
                    
                    
                    
                    
                    (209
                    )Total
      derivatives not designated as hedging instruments under SFAS No.
      133
                    
                    $
                    5
                    
                    
                    $
                    (771
                    )
                    
                    $
                    10
                    
                    
                    $
                    (589
                    )





(a)  Substantially
all of these contracts receive regulatory treatment.





The
following tables present the effect of derivative instruments on OCI (See Note
6C) and the Statements of Income for the three months ended March 31, 2009 and
2008:




Derivatives
      Designated as Hedging Instruments under SFAS No. 133Instrument
                                    
                                    Amount
      of Gain or (Loss) Recognized in OCI, Net of Tax on Derivatives(a)
                                    
                                    Location
      of Gain or (Loss) Reclassified from Accumulated OCI into Income(a)
                                    
                                    Amount
      of Gain or (Loss), Net of Tax Reclassified from Accumulated OCI into
      Income(a)
                                    
                                    Location
      of Gain or (Loss) Recognized in Income on Derivatives(b)
                                    
                                    Amount
      of Pre-tax Gain or (Loss) Recognized in Income on Derivatives(b)(in
      millions)
                                    
                                    2009
                                    
                                    
                                    2008
                                    
                                    
                                    
                                    2009
                                    
                                    
                                    2008
                                    
                                    
                                    
                                    2009
                                    
                                    
                                    2008Interest
      rate derivatives(c)
                                    
                                    $
                                    –
                                    
                                    
                                    $
                                    (4
                                    )
                                    Interest
      charges
                                    
                                    $
                                    –
                                    
                                    
                                    $
                                    –
                                    
                                    Interest
      charges
                                    
                                    $
                                    –
                                    
                                    
                                    $
                                    –




(a)
            Effective
      portion. (b)
              Related
      to ineffective portion and amount excluded from effectiveness
      testing.
 (c)
              Amounts
      in accumulated other comprehensive income related to terminated hedges are
      reclassified to earnings as the interest expense is recorded.  The
      effective portion of the hedges will be amortized to interest expense over
      the term of the related debt.






Derivatives
      Not Designated as Hedging Instruments under SFAS No.
    133Instrument
                          
                          Realized Gain or (Loss)(a)
                          
                          
                          Unrealized Gain or (Loss)(b)(in
      millions)
                          
                          2009
                          
                          
                          2008
                          
                          
                          2009
                          
                          
                          2008Commodity
      derivatives
                          
                          $
                          (109
                          )
                          
                          $
                          16
                          
                          
                          $
                          (84
                          )
                          
                          $
                          214




(a)
            After
      settlement of the derivaties and the fuel is consumed, gains or losses are
      passed through the fuel cost-recovery
clause. (b)
              Amounts
      are recorded in regulatory liabilities and assets, respectively, on the
      Balance Sheets until derivatives are
settled.


42


12.
            FINANCIAL INFORMATION
      BY BUSINESS SEGMENT




Our
reportable PEC and PEF business segments are primarily engaged in the
generation, transmission, distribution and sale of electricity in portions of
North Carolina, South Carolina and Florida. These electric operations also
distribute and sell electricity to other utilities, primarily on the east coast
of the United States.




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




Income of
discontinued operations is not included in the table presented below.  The
following information is for the three months ended March 31:




Income
      (Loss)Revenues
                      
                      
                      From
      Continuing(in
      millions)
                      
                      Unaffiliated
                      
                      
                      Intersegment
                      
                      
                      Total
                      
                      
                      Operations
                      
                      
                      Assets2009PEC
                      
                      $
                      1,178
                      
                      
                      $
                      –
                      
                      
                      $
                      1,178
                      
                      
                      $
                      127
                      
                      
                      $
                      13,210PEF
                      
                      
                      1,262
                      
                      
                      
                      –
                      
                      
                      
                      1,262
                      
                      
                      
                      88
                      
                      
                      
                      13,093Corporate
      and Other
                      
                      
                      2
                      
                      
                      
                      65
                      
                      
                      
                      67
                      
                      
                      
                      (32
                      )
                      
                      
                      18,824Eliminations
                      
                      
                      –
                      
                      
                      
                      (65
                      )
                      
                      
                      (65
                      )
                      
                      
                      –
                      
                      
                      
                      (14,224
                      )Totals
                      
                      $
                      2,442
                      
                      
                      $
                      –
                      
                      
                      $
                      2,442
                      
                      
                      $
                      183
                      
                      
                      $
                      30,9032008PEC
                      
                      $
                      1,068
                      
                      
                      $
                      –
                      
                      
                      $
                      1,068
                      
                      
                      $
                      122PEF
                      
                      
                      996
                      
                      
                      
                      –
                      
                      
                      
                      996
                      
                      
                      
                      66Corporate
      and Other
                      
                      
                      2
                      
                      
                      
                      82
                      
                      
                      
                      84
                      
                      
                      
                      (35
                      )Eliminations
                      
                      
                      –
                      
                      
                      
                      (82
                      )
                      
                      
                      (82
                      )
                      
                      
                      –Totals
                      
                      $
                      2,066
                      
                      
                      $
                      –
                      
                      
                      $
                      2,066
                      
                      
                      $
                      153


43


13.
            OTHER INCOME AND OTHER
      EXPENSE




Other
income and expense includes interest income and other income and expense items
as discussed below. Nonregulated energy and delivery services include power
protection services and mass market programs such as surge protection, appliance
services and area light sales, and delivery, transmission and substation work
for other utilities. The components of other, net as shown on the accompanying
Statements of Income were as follows:




Progress
      EnergyThree
      Months Ended March 31,(in
      millions)
                          
                          2009
                          
                          
                          2008Other incomeNonregulated
      energy and delivery services income
                          
                          $
                          5
                          
                          
                          $
                          7DIG
      Issue C20 amortization (see Note 11)
                          
                          
                          –
                          
                          
                          
                          1CVOs
      unrealized gain, net
                          
                          
                          7
                          
                          
                          
                          –Total
      other income
                          
                          
                          12
                          
                          
                          
                          8Other expenseNonregulated
      energy and delivery services expenses
                          
                          
                          4
                          
                          
                          
                          4Donations
                          
                          
                          3
                          
                          
                          
                          4Investment
      losses, net
                          
                          
                          –
                          
                          
                          
                          2Loss
      from equity investments, net
                          
                          
                          3
                          
                          
                          
                          1Derivative
      mark-to-market losses, net
                          
                          
                          1
                          
                          
                          
                          –Other,
      net
                          
                          
                          2
                          
                          
                          
                          2Total
      other expense
                          
                          
                          13
                          
                          
                          
                          13Other,
      net – Progress Energy
                          
                          $
                          (1
                          )
                          
                          $
                          (5
                          )





PECThree
      Months Ended March 31,(in
      millions)
                        
                        2009
                        
                        
                        2008Other incomeNonregulated
      energy and delivery services income
                        
                        $
                        –
                        
                        
                        $
                        3DIG
      Issue C20 amortization (see Note 11)
                        
                        
                        –
                        
                        
                        
                        1Investment
      gains, net
                        
                        
                        1
                        
                        
                        
                        1Total
      other income
                        
                        
                        1
                        
                        
                        
                        5Other expenseNonregulated
      energy and delivery services expenses
                        
                        
                        2
                        
                        
                        
                        1Donations
                        
                        
                        1
                        
                        
                        
                        2Loss
      from equity investments, net
                        
                        
                        2
                        
                        
                        
                        1Derivative
      mark-to-market losses, net
                        
                        
                        1
                        
                        
                        
                        –Other,
      net
                        
                        
                        2
                        
                        
                        
                        1Total
      other expense
                        
                        
                        8
                        
                        
                        
                        5Other,
      net – PEC
                        
                        $
                        (7
                        )
                        
                        $
                        –




44




PEFThree
      Months Ended March 31,(in
      millions)
                          
                          2009
                          
                          
                          2008Other incomeNonregulated
      energy and delivery services income
                          
                          $
                          5
                          
                          
                          $
                          4Other,
      net
                          
                          
                          –
                          
                          
                          
                          1Total
      other income
                          
                          
                          5
                          
                          
                          
                          5Other expenseNonregulated
      energy and delivery services expenses
                          
                          
                          2
                          
                          
                          
                          3Donations
                          
                          
                          2
                          
                          
                          
                          2Investment
      losses, net
                          
                          
                          1
                          
                          
                          
                          2Total
      other expense
                          
                          
                          5
                          
                          
                          
                          7Other,
      net – PEF
                          
                          $
                          –
                          
                          
                          $
                          (2
                          )










14.
            ENVIRONMENTAL
      MATTERS




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




A.
            HAZARDOUS
      AND SOLID WASTE




The
provisions of the Comprehensive Environmental Response, Compensation and
Liability Act of 1980, as amended (CERCLA), authorize the EPA to require the
cleanup of hazardous waste sites. This statute imposes retroactive joint and
several liability. Some states, including North Carolina, South Carolina and
Florida, have similar types of statutes. We are periodically notified by
regulators, including the EPA and various state agencies, of our involvement or
potential involvement in sites that may require investigation and/or
remediation. There are presently several sites with respect to which we have
been notified of our potential liability by the EPA, the state of North
Carolina, the state of Florida, or potentially responsible party (PRP) groups as
described below in greater detail. Various organic materials associated with the
production of manufactured gas, generally referred to as coal tar, are regulated
under federal and state laws. PEC and PEF are each PRPs at several manufactured
gas plant (MGP) sites. We are also currently in the process of assessing
potential costs and exposures at other sites. These costs are eligible for
regulatory recovery through either base rates or cost-recovery clauses. Both PEC
and PEF evaluate potential claims against other PRPs and insurance carriers and
plan to submit claims for cost recovery where appropriate. The outcome of
potential and pending claims cannot be predicted. A discussion of sites by legal
entity follows.




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




45




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




(in
      millions)
                
                March
      31, 2009
                
                
                December
      31, 2008PECMGP
      and other sites(a)
                
                $
                17
                
                
                $
                16PEFRemediation
      of distribution and substation transformers
                
                
                19
                
                
                
                22MGP
      and other sites
                
                
                15
                
                
                
                15Total
      PEF environmental remediation accruals(b)
                
                
                34
                
                
                
                37Total
      Progress Energy environmental remediation accruals
                
                $
                51
                
                
                $
                53




(a)
            Expected
      to be paid out over one to five years. (b)
              Expected
      to be paid out over one to 15
years.




PROGRESS
ENERGY




In
addition to the Utilities’ sites, discussed under “PEC” and “PEF” below, we
incurred indemnity obligations related to certain pre-closing liabilities of
divested subsidiaries, including certain environmental matters (See discussion
under Guarantees in Note 15B).




PEC




In 2006,
the NCUC and the SCPSC authorized PEC to defer and amortize certain
environmental remediation expenses. Remediation expenses not authorized to be
deferred are included in operation and maintenance (O&M)
expense.




Including
the Ward Transformer site located in Raleigh, N.C. (Ward), and MGP sites
discussed below, for the three months ended March 31, 2009, PEC accrued
approximately $3 million and spent approximately $2 million. For the three
months ended March 31, 2008, PEC accrued approximately $1 million and spent
approximately $2 million. These amounts primarily relate to the Ward
site.




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




During
the fourth quarter of 2004, the EPA advised PEC that it had been identified as a
PRP at the Ward site. The EPA offered PEC and a number of other PRPs the
opportunity to negotiate the removal action for the Ward site and reimbursement
to the EPA for the EPA’s past expenditures in addressing conditions at the Ward
site. Subsequently, PEC and other PRPs signed a settlement agreement, which
requires the participating PRPs to remediate the Ward site. At March 31, 2009
and December 31, 2008, PEC’s recorded liability for the site was approximately
$8 million and $7 million, respectively. Actual experience may differ from
current estimates, and it is probable that estimates will continue to change in
the future. On September 12, 2008, PEC filed an initial civil action against a
number of PRPs seeking contribution for and recovery of costs incurred in
remediating the Ward site, as well as a declaratory judgment that defendants are
jointly and severally liable for response costs at the site. On March 13, 2009,
a subsequent action was filed against additional PRPs, and on April 30, 2009,
suit was filed against the remaining approximately 160 PRPs. PEC and many of the
PRPs against whom suit has been filed are in active settlement negotiations. The
federal district court in which this matter is pending requires that
alternative dispute resolution be pursued initially in civil
litigation. The outcome of these matters cannot be predicted.




On
September 30, 2008, the EPA issued a Record of Decision for the operable unit
for stream segments downstream from the Ward site (Ward OU1) and advised 61
parties, including PEC, of their identification as PRPs for Ward OU1 and for the
operable unit for further investigation at the Ward facility and certain
adjacent areas (Ward OU2). The EPA’s estimate for the selected remedy for Ward
OU1 is approximately $6 million. The EPA offered PEC and the other PRPs the
opportunity to negotiate implementation of a response action for Ward OU1 and a
remedial




46




investigation
and feasibility study for Ward OU2, as well as reimbursement to the EPA of
approximately $1 million for the EPA’s past expenditures in addressing
conditions at the site. On January 19, 2009, PEC and several of the other
participating PRPs at the Ward site submitted a letter containing a good faith
response to the EPA’s special notice letter. Another group of PRPs separately
submitted a good faith response, which the EPA has advised will be used to
negotiate implementation of the required actions. Although a loss is considered
probable, an agreement among the PRPs for these matters has not been reached;
consequently, it is not possible at this time to reasonably estimate the total
amount of PEC’s obligation for Ward OU1 and Ward OU2.




PEF




PEF has
received approval from the FPSC for recovery through the environmental cost
recovery clause (ECRC) of the majority of costs associated with the remediation
of distribution and substation transformers. Under agreements with the Florida
Department of Environmental Protection (FDEP), PEF has reviewed all distribution
transformer sites and all substation sites for mineral oil-impacted soil caused
by equipment integrity issues. Should further distribution transformer sites be
identified outside of this population, the distribution O&M costs will not
be recoverable through the ECRC. Based on historical experience, PEF projects
costs will be between approximately $3 million and $4 million per year. For the
three months ended March 31, 2009, PEF made no material accruals and spent
approximately $3 million related to the remediation of transformers. For the
three months ended March 31, 2008, PEF accrued $2 million due to increases in
estimated remediation costs and spent approximately $6 million related to the
remediation of transformers. At March 31, 2009, PEF had recorded a regulatory
asset for the probable recovery of these costs through the ECRC.




The
accruals for MGP and other sites, in the previous table, relate to two former
MGP sites and other sites associated with PEF that have required, or are
anticipated to require, investigation and/or remediation. 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, 2009 and 2008,
PEF made no material accruals or expenditures.




B.
            AIR
      AND WATER QUALITY




At March
31, 2009 and December 31, 2008, we were subject to various current federal,
state and local environmental compliance laws and regulations governing air and
water quality, resulting in capital expenditures and increased O&M expenses.
These compliance laws and regulations included the Clean Air Interstate Rule
(CAIR), the Clean Air Visibility Rule (CAVR), the North Carolina Clean
Smokestacks Act, enacted in June 2002 (Clean Smokestacks Act) and mercury
regulation. PEC’s and PEF’s environmental compliance capital expenditures
related to these regulations began in 2002 and 2005, respectively. At March 31,
2009, cumulative environmental compliance capital expenditures to date with
regard to these environmental laws and regulations were $1.955 billion,
including $1.032 billion at PEC and $923 million at PEF. At December 31, 2008,
cumulative environmental compliance capital expenditures to date with regard to
these environmental laws and regulations were $1.859 billion, including $1.012
billion at PEC, which primarily relates to Clean Smokestacks Act projects, and
$847 million at PEF.




PEF
participated in a coalition of Florida utilities that filed a challenge to the
CAIR as it applied to Florida. PEF withdrew from the coalition during the fourth
quarter of 2008. On July 11, 2008, the U.S. Court of Appeals for the District of
Columbia (D.C. Court of Appeals) issued its decision on multiple challenges to
the CAIR, including the Florida challenge, which vacated the CAIR in its
entirety. On September 24, 2008, petitions for rehearing were filed by a number
of parties. On December 23, 2008, the D.C. Court of Appeals remanded the CAIR
without vacating the rule for the EPA to conduct further proceedings consistent
with the D.C. Court of Appeals’ prior opinion. The outcome of the EPA’s further
proceedings cannot be predicted. The D.C. Court of Appeals’ December 23, 2008
decision remanding the CAIR maintained its current implementation such that CAIR
satisfies best available retrofit technology (BART) for SO2 and
nitrogen oxides (NOx) for BART-affected units under the CAVR. Should this
determination change as the CAIR is revised, CAVR compliance eventually may
require consideration of NOx and SO2 emissions
in addition to particulate matter emissions for BART-eligible
units.




On
February 8, 2008, the D.C. Court of Appeals vacated the delisting determination
and the Clean Air Mercury Rule (CAMR). The three states in which the Utilities
operate adopted mercury regulations implementing CAMR and submitted their state
implementation rules to the EPA. It is uncertain how the decision that vacated
the federal CAMR will affect the state rules; however, state-specific provisions
are likely to remain in effect. The North




47




Carolina
mercury rule contains a requirement that all coal-fired units in the state
install mercury controls by December 31, 2017, and requires compliance plan
applications to be submitted in 2013. We are currently evaluating the impact of
these decisions. The outcome of these matters cannot be predicted.




PEF is
continuing construction of its in-process emission control projects. On December
18, 2008, PEF and the FDEP announced an agreement under which PEF will retire
Crystal River Units No. 1 and No. 2 (CR1 and CR2) as coal-fired units and
complete construction of its emission control projects at CR 4 and CR 5. CR1 and
CR2 will be retired after the second proposed nuclear unit at Levy completes its
first fuel cycle, which was anticipated to be around 2020. On May 1, 2009,
PEF announced that it expects the construction schedule to shift
by a minimum of 20 months from the originally estimated 2016 to 2018 timeframe
for the commercial operation dates of Levy. We are currently evaluating the
impacts of the schedule shift. We cannot predict the outcome of this
matter.




We
account for emission allowances as inventory using the average cost method. We
value inventory of the Utilities at historical cost consistent with ratemaking
treatment. The EPA is continuing to record allowance allocations under the CAIR
NOx trading program, in some cases for years beyond the estimated two-year
period for promulgation of a replacement rule. The EPA’s continued recording of
CAIR NOx allowance allocations does not guarantee that allowances will continue
to be usable for compliance after a replacement rule is finalized or that they
will continue to have value in the future. SO2 emission
allowances will be utilized to comply with existing Clean Air Act requirements.
PEF’s CAIR expenses, including NOx allowance inventory expense, are recoverable
through the ECRC. PEC’s and PEF’s emission allowance inventory balances have not
materially changed from December 31, 2008.




In June
2002, the Clean Smokestacks Act was enacted in North Carolina requiring the
state's electric utilities to reduce the emissions of NOx and SO2 from their
North Carolina coal-fired power plants in phases by 2013. Two of PEC’s largest
coal-fired generating units (the Roxboro No. 4 and Mayo Units) impacted by the
Clean Smokestacks Act are jointly owned. Pursuant to joint ownership agreements,
the joint owners are required to pay a portion of the costs of owning and
operating these plants. PEC has determined that the most cost-effective Clean
Smokestacks Act compliance strategy is to maximize the SO2 removal
from its larger coal-fired units, including Roxboro No. 4 and Mayo, so as to
avoid the installation of expensive emission controls on its smaller coal-fired
units. In order to address the joint owner's concerns that such a compliance
strategy would result in a disproportionate share of the cost of compliance for
the jointly owned units, in 2005 PEC entered into an agreement with the joint
owner to limit its aggregate costs associated with capital expenditures to
comply with the Clean Smokestacks Act to approximately $38 million. PEC recorded
a related liability for the joint owner's share of estimated costs in excess of
the contract amount. At March 31, 2009 and December 31, 2008, the amount of the
liability was $6 million and $10 million, respectively, based upon the
respective estimates for the remaining Clean Smokestacks Act compliance costs.
During the three months ended March 31, 2009, PEC made no additional accruals
and spent approximately $4 million that exceeded the joint owner limit. Because
PEC has taken a system-wide compliance approach, its North Carolina retail
ratepayers have significantly benefited from the strategy of focusing emission
reduction efforts on the jointly owned units, and, therefore, PEC believes that
any costs in excess of the joint owner’s share should be recovered from North
Carolina retail ratepayers, consistent with other capital expenditures
associated with PEC’s compliance with the Clean Smokestacks Act. On September 5,
2008, the NCUC ordered that PEC shall be allowed to include in rate base all
reasonable and prudently incurred environmental compliance costs in excess of
$584 million, including eligible compliance costs in excess of the joint owner’s
share, as the projects are closed to plant in service.







15.
            COMMITMENTS AND
      CONTINGENCIES




Contingencies
and significant changes to the commitments discussed in Note 22 in the 2008 Form
10-K are described below.




A.
            PURCHASE
      OBLIGATIONS




As part
of our ordinary course of business, we and the Utilities enter into various
long- and short-term contracts for fuel requirements at our generating plants.
Significant changes from the commitment amounts reported in Note 22A in the 2008
Form 10-K can result from new contracts, changes in existing contracts along
with the impact of fluctuations in current estimates of future market prices for
those contracts that are market price indexed. In most cases, these contracts
contain provisions for price adjustments, minimum purchase levels, and other
financial




48




commitments.
Additional commitments for fuel and related transportation will be required to
supply the Utilities' future needs.  At March 31, 2009, our and the
Utilities contractual cash obligations and other commercial commitments have not
changed materially from what was reported in the 2008 Form 10-K.  However,
on May 1, 2009, PEF annouced that it expects the construction
schedule for Levy to shift.  Although the overall schedule impact is
not certain at this time, PEF expects the schedule to shift from the 2016 to
2018 timeframe by a minimum of 20 months.  We anticipate amending the Levy
Engineering, Procurement, and Construction agreement due to the schedule shift
but cannot currently predict the impact such amendment might have on the
project's cost, if any.




B.
            GUARANTEES




As a part
of normal business, we enter into various agreements providing future financial
or performance assurances to third parties, which are outside the scope of FASB
Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for
Guarantees, Including Indirect Guarantees of Indebtedness of Others” (FIN 45).
Such agreements include guarantees, standby letters of credit and surety bonds.
At March 31, 2009, we do not believe conditions are likely for significant
performance under these guarantees. To the extent liabilities are incurred as a
result of the activities covered by the guarantees, such liabilities are
included in the accompanying Balance Sheets.





At March
31, 2009, we have issued guarantees and indemnifications of and for certain
asset performance, legal, tax and environmental matters to third parties,
including indemnifications made in connection with sales of businesses, which
are within the scope of FIN 45. Related to the sales of businesses, the latest
specified notice period extends until 2013 for the majority of legal, tax and
environmental matters provided for in the indemnification provisions.
Indemnifications for the performance of assets extend to 2016. For certain
matters for which we receive timely notice, our indemnity obligations may extend
beyond the notice period. Certain indemnifications have no limitations as to
time or maximum potential future payments. In 2005, PEC entered into an
agreement with the joint owner of certain facilities at the Mayo and Roxboro
plants to limit their aggregate costs associated with capital expenditures to
comply with the Clean Smokestacks Act and recognized a liability related to this
indemnification (See Note 14B). PEC’s maximum exposure cannot be determined. At
March 31, 2009, our estimated maximum exposure for guarantees and
indemnifications for which a maximum exposure is determinable was $458 million,
including $32 million at PEF. At March 31, 2009 and December 31, 2008, we have
recorded liabilities related to guarantees and indemnifications to third parties
of approximately $57 million and $61 million, respectively. These amounts
include $6 million and $10 million, respectively, for PEC and $8 million for PEF
at March 31, 2009, and December 31, 2008. During the three months ended March
31, 2009, PEC made no additional accruals and spent approximately $4 million
that exceeded the joint owner limit. As current estimates change, it is possible
that additional losses related to guarantees and indemnifications to third
parties, which could be material, may be recorded in the future.





In
addition, the Parent and a subsidiary have issued $300 million of guarantees for
certain payments of two wholly owned indirect subsidiaries. See Note 16 for
additional information.




C.
            OTHER
      COMMITMENTS AND CONTINGENCIES




SPENT
NUCLEAR FUEL MATTERS




Pursuant
to the Nuclear Waste Policy Act of 1982, the Utilities entered into contracts
with the United States Department of Energy (DOE) under which the DOE agreed to
begin taking spent nuclear fuel by no later than January 31, 1998. All similarly
situated utilities were required to sign the same standard
contract.




The DOE
failed to begin taking spent nuclear fuel by January 31, 1998. In January 2004,
the Utilities filed a complaint in the United States Court of Federal Claims
against the DOE, claiming that the DOE breached the Standard Contract for
Disposal of Spent Nuclear Fuel by failing to accept spent nuclear fuel from our
various facilities on or before January 31, 1998. Approximately 60 cases
involving the government’s actions in connection with spent nuclear fuel are
currently pending in the Court of Federal Claims. The Utilities have asserted
nearly $91 million in damages incurred between January 31, 1998 and December 31,
2005; the time period set by the court for damages in this case. The Utilities
will be free to file subsequent damage claims as they incur additional
costs.




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




49




and
reduced the damage award by an immaterial amount. On August 15, 2008, the
Department of Justice appealed the United States Court of Federal Claims ruling
to the D.C. Court of Appeals.  Oral arguments were held on May 4,
2009.  In the event that the Utilities recover damages in this matter, such
recovery is not expected to have a material
impact on the Utilities’ results of operations given the anticipated regulatory
and accounting treatment. However, the Utilities cannot predict the outcome of
this matter.




SYNTHETIC
FUELS MATTERS




A number
of our subsidiaries and affiliates are parties to two lawsuits arising out of an
Asset Purchase Agreement dated as of October 19, 1999, by and among U.S. Global,
LLC (Global); Earthco; certain affiliates of Earthco; EFC Synfuel LLC (which was
owned indirectly by Progress Energy, Inc.) and certain of its affiliates,
including Solid Energy LLC; Solid Fuel LLC; Ceredo Synfuel LLC; Gulf Coast
Synfuel LLC (currently named Sandy River Synfuel LLC) (collectively, the
Progress Affiliates), as amended by an amendment to Purchase Agreement as of
August 23, 2000 (the Asset Purchase Agreement). Global has asserted (1) that
pursuant to the Asset Purchase Agreement, it is entitled to an interest in two
synthetic fuels facilities previously owned by the Progress Affiliates and an
option to purchase additional interests in the two synthetic fuels facilities,
(2) that it is entitled to damages because the Progress Affiliates prohibited it
from procuring purchasers for the synthetic fuels facilities and (3) a number of
tort claims are related to the contracts.




The first
suit, U.S. Global, LLC v.
Progress Energy, Inc. et al. (the Florida Global Case), asserts the above
claims in a case filed in the Circuit Court for Broward County, Fla., in March
2003, and requests an unspecified amount of compensatory damages, as well as
declaratory relief. The Progress Affiliates have answered the Complaint by
generally denying all of Global’s substantive allegations and asserting numerous
substantial affirmative defenses. The case is at issue, but neither party has
requested a trial. The parties are currently engaged in discovery in the Florida
Global Case.




The
second suit, Progress Synfuel
Holdings, Inc. et al. v. U.S. Global, LLC (the North Carolina Global
Case), was filed by the Progress Affiliates in the Superior Court for Wake
County, N.C., seeking declaratory relief consistent with our interpretation of
the Asset Purchase Agreement. Global was served with the North Carolina Global
Case on April 17, 2003.




On May
15, 2003, Global moved to dismiss the North Carolina Global Case for lack of
personal jurisdiction over Global. In the alternative, Global requested that the
court decline to exercise its discretion to hear the Progress Affiliates’
declaratory judgment action. On August 7, 2003, the Wake County Superior Court
denied Global’s motion to dismiss, but stayed the North Carolina Global Case,
pending the outcome of the Florida Global Case. The Progress Affiliates appealed
the superior court’s order staying the case. By order dated September 7, 2004,
the North Carolina Court of Appeals dismissed the Progress Affiliates’ appeal.
Since that time, the parties have been engaged in discovery in the Florida
Global Case.




In
December 2006, we reached agreement with Global to settle an additional claim in
the suit related to amounts due to Global that were placed in escrow pursuant to
a defined tax event. Upon the successful resolution of the IRS audit of the
Earthco synthetic fuels facilities in 2006, and pursuant to a settlement
agreement, the escrow totaling $42 million at December 31, 2006, was paid to
Global in January 2007.




In
January 2008, Global agreed to simplify the Florida action by dismissing the
tort claims. The Florida Global Case continues now under contract theories
alone. The case is scheduled to go to trial in September 2009. We cannot predict
the outcome of this matter.




OTHER
LITIGATION MATTERS




We and
our subsidiaries are involved in various litigation matters in the ordinary
course of business, some of which involve substantial amounts. Where
appropriate, we have made accruals and disclosures 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.




50







16.
            CONDENSED
      CONSOLIDATING STATEMENTS




As
discussed in Note 23 in the 2008 Form 10-K, we have guaranteed certain payments
of two wholly owned indirect subsidiaries, FPC Capital I (the Trust) and Florida
Progress Funding Corporation (Funding Corp.) since September 2005. Our
guarantees are joint and several, full and unconditional and are in addition to
the joint and several, full and
unconditional guarantees previously issued to the Trust and Funding Corp. by
Florida Progress. Our subsidiaries have provisions restricting the payment of
dividends to the Parent in certain limited circumstances and as disclosed in
Note 11B in the 2008 Form 10-K, there were no restrictions on PEC’s or PEF’s
retained earnings.




The Trust
is a special-purpose entity and was deconsolidated in 2003 in accordance with
the provisions of FIN 46R. The deconsolidation was not material to our financial
statements. Separate financial statements and other disclosures concerning the
Trust have not been presented because we believe that such information is not
material to investors.




Presented
below are the condensed consolidating Statements of Income, Balance Sheets and
Cash Flows as required by Rule 3-10 of Regulation S-X. In these condensed
consolidating statements, the Parent column includes the financial results of
the parent holding company only. The Subsidiary Guarantor column includes the
consolidated financial results of Florida Progress only, which is primarily
comprised of its wholly owned subsidiary PEF. The Non-guarantor Subsidiary
column includes the consolidated financial results of our wholly owned
subsidiary PEC. The Other column includes the consolidated financial results of
all other non-guarantor subsidiaries and elimination entries for all
intercompany transactions. Financial statements for PEC and PEF are separately
presented elsewhere in this Form 10-Q. All applicable corporate expenses have
been allocated appropriately among the guarantor and non-guarantor subsidiaries.
The financial information may not necessarily be indicative of results of
operations or financial position had the Subsidiary Guarantor or other
non-guarantor subsidiaries operated as independent entities.


51




Condensed
      Consolidating Statement of Income
                    Three
      Months Ended March 31, 2009(in
      millions)
                  
                  Parent
                  
                  
                  Subsidiary
      Guarantor
                  
                  
                  Non-
                    Guarantor
                    Subsidiary
                  
                  
                  Other
                  
                  
                  Progress
      Energy, Inc.Operating
      revenues
                  
                  $
                  –
                  
                  
                  $
                  1,264
                  
                  
                  $
                  1,178
                  
                  
                  $
                  –
                  
                  
                  $
                  2,442Operating
      expensesFuel
      used in electric generation
                  
                  
                  –
                  
                  
                  
                  512
                  
                  
                  
                  442
                  
                  
                  
                  –
                  
                  
                  
                  954Purchased
      power
                  
                  
                  –
                  
                  
                  
                  160
                  
                  
                  
                  57
                  
                  
                  
                  –
                  
                  
                  
                  217Operation
      and maintenance
                  
                  
                  1
                  
                  
                  
                  202
                  
                  
                  
                  259
                  
                  
                  
                  (9
                  )
                  
                  
                  453Depreciation,
      amortization and accretion
                  
                  
                  –
                  
                  
                  
                  160
                  
                  
                  
                  117
                  
                  
                  
                  3
                  
                  
                  
                  280Taxes
      other than on income
                  
                  
                  –
                  
                  
                  
                  88
                  
                  
                  
                  54
                  
                  
                  
                  1
                  
                  
                  
                  143Other
                  
                  
                  –
                  
                  
                  
                  2
                  
                  
                  
                  –
                  
                  
                  
                  –
                  
                  
                  
                  2Total
      operating expenses
                  
                  
                  1
                  
                  
                  
                  1,124
                  
                  
                  
                  929
                  
                  
                  
                  (5
                  )
                  
                  
                  2,049Operating
      (loss) income
                  
                  
                  (1
                  )
                  
                  
                  140
                  
                  
                  
                  249
                  
                  
                  
                  5
                  
                  
                  
                  393Other
      income (expense)Interest
      income
                  
                  
                  3
                  
                  
                  
                  1
                  
                  
                  
                  2
                  
                  
                  
                  (2
                  )
                  
                  
                  4Allowance
      for equity funds used during construction
                  
                  
                  –
                  
                  
                  
                  30
                  
                  
                  
                  9
                  
                  
                  
                  –
                  
                  
                  
                  39Other,
      net
                  
                  
                  7
                  
                  
                  
                  –
                  
                  
                  
                  (7
                  )
                  
                  
                  (1
                  )
                  
                  
                  (1
                  )Total
      other income (expense), net
                  
                  
                  10
                  
                  
                  
                  31
                  
                  
                  
                  4
                  
                  
                  
                  (3
                  )
                  
                  
                  42Interest
      chargesInterest
      charges
                  
                  
                  52
                  
                  
                  
                  72
                  
                  
                  
                  57
                  
                  
                  
                  (2
                  )
                  
                  
                  179Allowance
      for borrowed funds used during construction
                  
                  
                  –
                  
                  
                  
                  (9
                  )
                  
                  
                  (3
                  )
                  
                  
                  –
                  
                  
                  
                  (12
                  )Total
      interest charges, net
                  
                  
                  52
                  
                  
                  
                  63
                  
                  
                  
                  54
                  
                  
                  
                  (2
                  )
                  
                  
                  167(Loss)
      income from continuing operations before income tax and equity in earnings
      of consolidated subsidiaries
                  
                  
                  (43
                  )
                  
                  
                  108
                  
                  
                  
                  199
                  
                  
                  
                  4
                  
                  
                  
                  268Income
      tax (benefit) expense
                  
                  
                  (13
                  )
                  
                  
                  21
                  
                  
                  
                  71
                  
                  
                  
                  6
                  
                  
                  
                  85Equity
      in earnings of consolidated subsidiaries
                  
                  
                  211
                  
                  
                  
                  –
                  
                  
                  
                  –
                  
                  
                  
                  (211
                  )
                  
                  
                  –Income
      (loss) from continuing operations
                  
                  
                  181
                  
                  
                  
                  87
                  
                  
                  
                  128
                  
                  
                  
                  (213
                  )
                  
                  
                  183Discontinued
      operations, net of tax
                  
                  
                  1
                  
                  
                  
                  (1
                  )
                  
                  
                  –
                  
                  
                  
                  –
                  
                  
                  
                  –Net
      income (loss)
                  
                  
                  182
                  
                  
                  
                  86
                  
                  
                  
                  128
                  
                  
                  
                  (213
                  )
                  
                  
                  183Net
      income attributable to noncontrolling interests, net of
tax
                  
                  
                  –
                  
                  
                  
                  (1
                  )
                  
                  
                  –
                  
                  
                  
                  –
                  
                  
                  
                  (1
                  )Net
      income (loss) attributable to controlling interests
                  
                  $
                  182
                  
                  
                  $
                  85
                  
                  
                  $
                  128
                  
                  
                  $
                  (213
                  )
                  
                  $
                  182


52


Condensed
      Consolidating Statement of Income
                      Three
      Months Ended March 31, 2008(in
      millions)
                    
                    Parent
                    
                    
                    Subsidiary
      Guarantor
                    
                    
                    Non-
                      Guarantor
                      Subsidiary
                    
                    
                    Other
                    
                    
                    Progress
      Energy, Inc.Operating
      revenues
                    
                    $
                    –
                    
                    
                    $
                    998
                    
                    
                    $
                    1,068
                    
                    
                    $
                    –
                    
                    
                    $
                    2,066Operating
      expensesFuel
      used in electric generation
                    
                    
                    –
                    
                    
                    
                    341
                    
                    
                    
                    356
                    
                    
                    
                    –
                    
                    
                    
                    697Purchased
      power
                    
                    
                    –
                    
                    
                    
                    183
                    
                    
                    
                    49
                    
                    
                    
                    –
                    
                    
                    
                    232Operation
      and maintenance
                    
                    
                    –
                    
                    
                    
                    203
                    
                    
                    
                    248
                    
                    
                    
                    (8
                    )
                    
                    
                    443Depreciation,
      amortization and accretion
                    
                    
                    –
                    
                    
                    
                    76
                    
                    
                    
                    126
                    
                    
                    
                    4
                    
                    
                    
                    206Taxes
      other than on income
                    
                    
                    –
                    
                    
                    
                    71
                    
                    
                    
                    50
                    
                    
                    
                    –
                    
                    
                    
                    121Other
                    
                    
                    –
                    
                    
                    
                    2
                    
                    
                    
                    (1
                    )
                    
                    
                    1
                    
                    
                    
                    2Total
      operating expenses
                    
                    
                    –
                    
                    
                    
                    876
                    
                    
                    
                    828
                    
                    
                    
                    (3
                    )
                    
                    
                    1,701Operating
      income
                    
                    
                    –
                    
                    
                    
                    122
                    
                    
                    
                    240
                    
                    
                    
                    3
                    
                    
                    
                    365Other
      income (expense)Interest
      income
                    
                    
                    4
                    
                    
                    
                    –
                    
                    
                    
                    5
                    
                    
                    
                    (2
                    )
                    
                    
                    7Allowance
      for equity funds used during construction
                    
                    
                    –
                    
                    
                    
                    19
                    
                    
                    
                    4
                    
                    
                    
                    –
                    
                    
                    
                    23Other,
      net
                    
                    
                    –
                    
                    
                    
                    (4
                    )
                    
                    
                    –
                    
                    
                    
                    (1
                    )
                    
                    
                    (5
                    )Total
      other income (expense), net
                    
                    
                    4
                    
                    
                    
                    15
                    
                    
                    
                    9
                    
                    
                    
                    (3
                    )
                    
                    
                    25Interest
      chargesInterest
      charges
                    
                    
                    48
                    
                    
                    
                    57
                    
                    
                    
                    58
                    
                    
                    
                    (2
                    )
                    
                    
                    161Allowance
      for borrowed funds used during construction
                    
                    
                    –
                    
                    
                    
                    (6
                    )
                    
                    
                    (2
                    )
                    
                    
                    –
                    
                    
                    
                    (8
                    )Total
      interest charges, net
                    
                    
                    48
                    
                    
                    
                    51
                    
                    
                    
                    56
                    
                    
                    
                    (2
                    )
                    
                    
                    153(Loss)
      income from continuing operations before income tax and equity in earnings
      of consolidated subsidiaries
                    
                    
                    (44
                    )
                    
                    
                    86
                    
                    
                    
                    193
                    
                    
                    
                    2
                    
                    
                    
                    237Income
      tax (benefit) expense
                    
                    
                    (18
                    )
                    
                    
                    27
                    
                    
                    
                    70
                    
                    
                    
                    5
                    
                    
                    
                    84Equity
      in earnings of consolidated subsidiaries
                    
                    
                    235
                    
                    
                    
                    –
                    
                    
                    
                    –
                    
                    
                    
                    (235
                    )
                    
                    
                    –Income
      (loss) from continuing operations
                    
                    
                    209
                    
                    
                    
                    59
                    
                    
                    
                    123
                    
                    
                    
                    (238
                    )
                    
                    
                    153Discontinued
      operations, net of tax
                    
                    
                    –
                    
                    
                    
                    57
                    
                    
                    
                    –
                    
                    
                    
                    4
                    
                    
                    
                    61Net
      income (loss)
                    
                    
                    209
                    
                    
                    
                    116
                    
                    
                    
                    123
                    
                    
                    
                    (234
                    )
                    
                    
                    214Net
      income attributable to noncontrolling interests, net of
tax
                    
                    
                    –
                    
                    
                    
                    (5
                    )
                    
                    
                    –
                    
                    
                    
                    –
                    
                    
                    
                    (5
                    )Net
      income (loss) attributable to controlling interests
                    
                    $
                    209
                    
                    
                    $
                    111
                    
                    
                    $
                    123
                    
                    
                    $
                    (234
                    )
                    
                    $
                    209





53





Condensed
      Consolidating Balance Sheet
                        March
      31, 2009(in
      millions)
                      
                      Parent
                      
                      
                      Subsidiary
      Guarantor
                      
                      
                      Non-
                        Guarantor
                        Subsidiary
                      
                      
                      Other
                      
                      
                      Progress
      Energy, Inc.ASSETSUtility
      plant, net
                      
                      $
                      –
                      
                      
                      $
                      9,056
                      
                      
                      $
                      9,460
                      
                      
                      $
                      120
                      
                      
                      $
                      18,636Current
      assetsCash
      and cash equivalents
                      
                      
                      586
                      
                      
                      
                      24
                      
                      
                      
                      21
                      
                      
                      
                      1
                      
                      
                      
                      632Notes
      receivable from affiliated companies
                      
                      
                      446
                      
                      
                      
                      73
                      
                      
                      
                      120
                      
                      
                      
                      (639
                      )
                      
                      
                      –Regulatory
      assets
                      
                      
                      –
                      
                      
                      
                      226
                      
                      
                      
                      163
                      
                      
                      
                      –
                      
                      
                      
                      389Derivative
      collateral posted
                      
                      
                      –
                      
                      
                      
                      535
                      
                      
                      
                      28
                      
                      
                      
                      –
                      
                      
                      
                      563Prepayments
      and other current assets
                      
                      
                      26
                      
                      
                      
                      1,186
                      
                      
                      
                      1,190
                      
                      
                      
                      2
                      
                      
                      
                      2,404Total
      current assets
                      
                      
                      1,058
                      
                      
                      
                      2,044
                      
                      
                      
                      1,522
                      
                      
                      
                      (636
                      )
                      
                      
                      3,988Deferred
      debits and other assetsInvestment
      in consolidated subsidiaries
                      
                      
                      12,134
                      
                      
                      
                      –
                      
                      
                      
                      –
                      
                      
                      
                      (12,134
                      )
                      
                      
                      –Regulatory
      assets
                      
                      
                      –
                      
                      
                      
                      1,567
                      
                      
                      
                      1,279
                      
                      
                      
                      (1
                      )
                      
                      
                      2,845Goodwill
                      
                      
                      –
                      
                      
                      
                      –
                      
                      
                      
                      –
                      
                      
                      
                      3,655
                      
                      
                      
                      3,655Other
      assets and deferred debits
                      
                      
                      164
                      
                      
                      
                      572
                      
                      
                      
                      949
                      
                      
                      
                      94
                      
                      
                      
                      1,779Total
      deferred debits and other assets
                      
                      
                      12,298
                      
                      
                      
                      2,139
                      
                      
                      
                      2,228
                      
                      
                      
                      (8,386
                      )
                      
                      
                      8,279Total
      assets
                      
                      $
                      13,356
                      
                      
                      $
                      13,239
                      
                      
                      $
                      13,210
                      
                      
                      $
                      (8,902
                      )
                      
                      $
                      30,903CAPITALIZATION
      AND LIABILITIESEquityCommon
      stock equity
                      
                      $
                      9,261
                      
                      
                      $
                      3,792
                      
                      
                      $
                      4,244
                      
                      
                      $
                      (8,036
                      )
                      
                      $
                      9,261Noncontrolling
      interests
                      
                      
                      –
                      
                      
                      
                      2
                      
                      
                      
                      4
                      
                      
                      
                      –
                      
                      
                      
                      6Total
      equity
                      
                      
                      9,261
                      
                      
                      
                      3,794
                      
                      
                      
                      4,248
                      
                      
                      
                      (8,036
                      )
                      
                      
                      9,267Preferred
      stock of subsidiaries
                      
                      
                      –
                      
                      
                      
                      34
                      
                      
                      
                      59
                      
                      
                      
                      –
                      
                      
                      
                      93Long-term
      debt, affiliate
                      
                      
                      –
                      
                      
                      
                      309
                      
                      
                      
                      –
                      
                      
                      
                      (37
                      )
                      
                      
                      272Long-term
      debt, net
                      
                      
                      3,243
                      
                      
                      
                      4,182
                      
                      
                      
                      3,708
                      
                      
                      
                      –
                      
                      
                      
                      11,133Total
      capitalization
                      
                      
                      12,504
                      
                      
                      
                      8,319
                      
                      
                      
                      8,015
                      
                      
                      
                      (8,073
                      )
                      
                      
                      20,765Current
      liabilitiesShort-term
      debt
                      
                      
                      500
                      
                      
                      
                      130
                      
                      
                      
                      –
                      
                      
                      
                      –
                      
                      
                      
                      630Notes
      payable to affiliated companies
                      
                      
                      –
                      
                      
                      
                      660
                      
                      
                      
                      –
                      
                      
                      
                      (660
                      )
                      
                      
                      –Derivative
      liabilities
                      
                      
                      –
                      
                      
                      
                      496
                      
                      
                      
                      60
                      
                      
                      
                      –
                      
                      
                      
                      556Other
      current liabilities
                      
                      
                      316
                      
                      
                      
                      922
                      
                      
                      
                      705
                      
                      
                      
                      (66
                      )
                      
                      
                      1,877Total
      current liabilities
                      
                      
                      816
                      
                      
                      
                      2,208
                      
                      
                      
                      765
                      
                      
                      
                      (726
                      )
                      
                      
                      3,063Deferred
      credits and other liabilitiesNoncurrent
      income tax liabilities
                      
                      
                      –
                      
                      
                      
                      136
                      
                      
                      
                      1,162
                      
                      
                      
                      (410
                      )
                      
                      
                      888Regulatory
      liabilities
                      
                      
                      –
                      
                      
                      
                      1,029
                      
                      
                      
                      995
                      
                      
                      
                      117
                      
                      
                      
                      2,141Other
      liabilities and deferred credits
                      
                      
                      36
                      
                      
                      
                      1,547
                      
                      
                      
                      2,273
                      
                      
                      
                      190
                      
                      
                      
                      4,046Total
      deferred credits and other liabilities
                      
                      
                      36
                      
                      
                      
                      2,712
                      
                      
                      
                      4,430
                      
                      
                      
                      (103
                      )
                      
                      
                      7,075Total
      capitalization and liabilities
                      
                      $
                      13,356
                      
                      
                      $
                      13,239
                      
                      
                      $
                      13,210
                      
                      
                      $
                      (8,902
                      )
                      
                      $
                      30,903





54






Condensed
      Consolidating Balance Sheet
                          December
      31, 2008(in
      millions)
                        
                        Parent
                        
                        
                        Subsidiary
      Guarantor
                        
                        
                        Non-Guarantor
      Subsidiary
                        
                        
                        Other
                        
                        
                        Progress
      Energy, Inc.ASSETSUtility
      plant, net
                        
                        $
                        –
                        
                        
                        $
                        8,790
                        
                        
                        $
                        9,385
                        
                        
                        $
                        118
                        
                        
                        $
                        18,293Current
      assetsCash
      and cash equivalents
                        
                        
                        88
                        
                        
                        
                        73
                        
                        
                        
                        18
                        
                        
                        
                        1
                        
                        
                        
                        180Notes
      receivable from affiliated companies
                        
                        
                        34
                        
                        
                        
                        44
                        
                        
                        
                        55
                        
                        
                        
                        (133
                        )
                        
                        
                        –Regulatory
      assets
                        
                        
                        –
                        
                        
                        
                        326
                        
                        
                        
                        207
                        
                        
                        
                        –
                        
                        
                        
                        533Derivative
      collateral posted
                        
                        
                        –
                        
                        
                        
                        335
                        
                        
                        
                        18
                        
                        
                        
                        –
                        
                        
                        
                        353Prepayments
      and other current assets
                        
                        
                        48
                        
                        
                        
                        1,138
                        
                        
                        
                        1,272
                        
                        
                        
                        (4
                        )
                        
                        
                        2,454Total
      current assets
                        
                        
                        170
                        
                        
                        
                        1,916
                        
                        
                        
                        1,570
                        
                        
                        
                        (136
                        )
                        
                        
                        3,520Deferred
      debits and other assetsInvestment
      in consolidated subsidiaries
                        
                        
                        11,924
                        
                        
                        
                        –
                        
                        
                        
                        –
                        
                        
                        
                        (11,924
                        )
                        
                        
                        –Regulatory
      assets
                        
                        
                        –
                        
                        
                        
                        1,324
                        
                        
                        
                        1,243
                        
                        
                        
                        –
                        
                        
                        
                        2,567Goodwill
                        
                        
                        –
                        
                        
                        
                        –
                        
                        
                        
                        –
                        
                        
                        
                        3,655
                        
                        
                        
                        3,655Other
      assets and deferred debits
                        
                        
                        155
                        
                        
                        
                        613
                        
                        
                        
                        967
                        
                        
                        
                        103
                        
                        
                        
                        1,838Total
      deferred debits and other assets
                        
                        
                        12,079
                        
                        
                        
                        1,937
                        
                        
                        
                        2,210
                        
                        
                        
                        (8,166
                        )
                        
                        
                        8,060Total
      assets
                        
                        $
                        12,249
                        
                        
                        $
                        12,643
                        
                        
                        $
                        13,165
                        
                        
                        $
                        (8,184
                        )
                        
                        $
                        29,873CAPITALIZATION
      AND LIABILITIESEquityCommon
      stock equity
                        
                        $
                        8,687
                        
                        
                        $
                        3,519
                        
                        
                        $
                        4,301
                        
                        
                        $
                        (7,820
                        )
                        
                        $
                        8,687Noncontrolling
      interests
                        
                        
                        –
                        
                        
                        
                        3
                        
                        
                        
                        4
                        
                        
                        
                        (1
                        )
                        
                        
                        6Total
      equity
                        
                        
                        8,687
                        
                        
                        
                        3,522
                        
                        
                        
                        4,305
                        
                        
                        
                        (7,821
                        )
                        
                        
                        8,693Preferred
      stock of subsidiaries
                        
                        
                        –
                        
                        
                        
                        34
                        
                        
                        
                        59
                        
                        
                        
                        –
                        
                        
                        
                        93Long-term
      debt, affiliate
                        
                        
                        –
                        
                        
                        
                        309
                        
                        
                        
                        –
                        
                        
                        
                        (37
                        )
                        
                        
                        272Long-term
      debt, net
                        
                        
                        2,696
                        
                        
                        
                        4,182
                        
                        
                        
                        3,509
                        
                        
                        
                        –
                        
                        
                        
                        10,387Total
      capitalization
                        
                        
                        11,383
                        
                        
                        
                        8,047
                        
                        
                        
                        7,873
                        
                        
                        
                        (7,858
                        )
                        
                        
                        19,445Current
      liabilitiesShort-term
      debt
                        
                        
                        569
                        
                        
                        
                        371
                        
                        
                        
                        110
                        
                        
                        
                        –
                        
                        
                        
                        1,050Notes
      payable to affiliated companies
                        
                        
                        –
                        
                        
                        
                        206
                        
                        
                        
                        –
                        
                        
                        
                        (206
                        )
                        
                        
                        –Derivative
      liabilities
                        
                        
                        31
                        
                        
                        
                        380
                        
                        
                        
                        82
                        
                        
                        
                        –
                        
                        
                        
                        493Other
      current liabilities
                        
                        
                        220
                        
                        
                        
                        964
                        
                        
                        
                        773
                        
                        
                        
                        (14
                        )
                        
                        
                        1,943Total
      current liabilities
                        
                        
                        820
                        
                        
                        
                        1,921
                        
                        
                        
                        965
                        
                        
                        
                        (220
                        )
                        
                        
                        3,486Deferred
      credits and other liabilitiesNoncurrent
      income tax liabilities
                        
                        
                        1
                        
                        
                        
                        118
                        
                        
                        
                        1,111
                        
                        
                        
                        (412
                        )
                        
                        
                        818Regulatory
      liabilities
                        
                        
                        –
                        
                        
                        
                        1,076
                        
                        
                        
                        987
                        
                        
                        
                        118
                        
                        
                        
                        2,181Other
      liabilities and deferred credits
                        
                        
                        45
                        
                        
                        
                        1,481
                        
                        
                        
                        2,229
                        
                        
                        
                        188
                        
                        
                        
                        3,943Total
      deferred credits and other liabilities
                        
                        
                        46
                        
                        
                        
                        2,675
                        
                        
                        
                        4,327
                        
                        
                        
                        (106
                        )
                        
                        
                        6,942Total
      capitalization and liabilities
                        
                        $
                        12,249
                        
                        
                        $
                        12,643
                        
                        
                        $
                        13,165
                        
                        
                        $
                        (8,184
                        )
                        
                        $
                        29,873


55





Condensed
      Consolidating Statement of Cash Flows
                    Three
      Months Ended March 31, 2009(in
      millions)
                  
                  Parent
                  
                  
                  Subsidiary
      Guarantor
                  
                  
                  Non-Guarantor
      Subsidiary
                  
                  
                  Other
                  
                  
                  Progress
      Energy, Inc.Net
      cash provided (used) by operating activities
                  
                  $
                  143
                  
                  
                  $
                  53
                  
                  
                  $
                  397
                  
                  
                  $
                  (198
                  )
                  
                  $
                  395Investing
      activitiesGross
      property additions
                  
                  
                  –
                  
                  
                  
                  (462
                  )
                  
                  
                  (181
                  )
                  
                  
                  4
                  
                  
                  
                  (639
                  )Nuclear
      fuel additions
                  
                  
                  –
                  
                  
                  
                  (9
                  )
                  
                  
                  (28
                  )
                  
                  
                  –
                  
                  
                  
                  (37
                  )Purchases
      of available-for-sale securities and other investments
                  
                  
                  –
                  
                  
                  
                  (277
                  )
                  
                  
                  (420
                  )
                  
                  
                  (19
                  )
                  
                  
                  (716
                  )Proceeds
      from available-for-sale securities and other investments
                  
                  
                  –
                  
                  
                  
                  280
                  
                  
                  
                  407
                  
                  
                  
                  19
                  
                  
                  
                  706Changes
      in advances to affiliated companies
                  
                  
                  (412
                  )
                  
                  
                  (29
                  )
                  
                  
                  (65
                  )
                  
                  
                  506
                  
                  
                  
                  –Return
      of investment in consolidated subsidiaries
                  
                  
                  12
                  
                  
                  
                  –
                  
                  
                  
                  –
                  
                  
                  
                  (12
                  )
                  
                  
                  –Contributions
      to consolidated subsidiaries
                  
                  
                  (191
                  )
                  
                  
                  –
                  
                  
                  
                  –
                  
                  
                  
                  191
                  
                  
                  
                  –Other
      investing activities
                  
                  
                  –
                  
                  
                  
                  (3
                  )
                  
                  
                  –
                  
                  
                  
                  (2
                  )
                  
                  
                  (5
                  )Net
      cash (used) provided by investing activities
                  
                  
                  (591
                  )
                  
                  
                  (500
                  )
                  
                  
                  (287
                  )
                  
                  
                  687
                  
                  
                  
                  (691
                  )Financing
      activitiesIssuance
      of common stock
                  
                  
                  545
                  
                  
                  
                  –
                  
                  
                  
                  –
                  
                  
                  
                  –
                  
                  
                  
                  545Dividends
      paid on common stock
                  
                  
                  (173
                  )
                  
                  
                  –
                  
                  
                  
                  –
                  
                  
                  
                  –
                  
                  
                  
                  (173
                  )Dividends
      paid to parent
                  
                  
                  –
                  
                  
                  
                  (1
                  )
                  
                  
                  (200
                  )
                  
                  
                  201
                  
                  
                  
                  –Payments
      of short-term debt with original maturities greater than 90
      days
                  
                  
                  (29
                  )
                  
                  
                  –
                  
                  
                  
                  –
                  
                  
                  
                  –
                  
                  
                  
                  (29
                  )Net
      decrease in short-term debt
                  
                  
                  (139
                  )
                  
                  
                  (241
                  )
                  
                  
                  (110
                  )
                  
                  
                  –
                  
                  
                  
                  (490
                  )Proceeds
      from issuance of long-term debt, net
                  
                  
                  743
                  
                  
                  
                  –
                  
                  
                  
                  595
                  
                  
                  
                  –
                  
                  
                  
                  1,338Retirement
      of long-term debt
                  
                  
                  –
                  
                  
                  
                  –
                  
                  
                  
                  (400
                  )
                  
                  
                  –
                  
                  
                  
                  (400
                  )Cash
      distributions to noncontrolling interests of consolidated
      subsidiaries
                  
                  
                  –
                  
                  
                  
                  (1
                  )
                  
                  
                  –
                  
                  
                  
                  –
                  
                  
                  
                  (1
                  )Changes
      in advances from affiliated companies
                  
                  
                  –
                  
                  
                  
                  454
                  
                  
                  
                  –
                  
                  
                  
                  (454
                  )
                  
                  
                  –Contributions
      from parent
                  
                  
                  –
                  
                  
                  
                  188
                  
                  
                  
                  8
                  
                  
                  
                  (196
                  )
                  
                  
                  –Other
      financing activities
                  
                  
                  (1
                  )
                  
                  
                  (1
                  )
                  
                  
                  –
                  
                  
                  
                  (40
                  )
                  
                  
                  (42
                  )Net
      cash provided (used) by financing activities
                  
                  
                  946
                  
                  
                  
                  398
                  
                  
                  
                  (107
                  )
                  
                  
                  (489
                  )
                  
                  
                  748Net
      increase (decrease) in cash and cash equivalents
                  
                  
                  498
                  
                  
                  
                  (49
                  )
                  
                  
                  3
                  
                  
                  
                  –
                  
                  
                  
                  452Cash
      and cash equivalents at beginning of period
                  
                  
                  88
                  
                  
                  
                  73
                  
                  
                  
                  18
                  
                  
                  
                  1
                  
                  
                  
                  180Cash
      and cash equivalents at end of period
                  
                  $
                  586
                  
                  
                  $
                  24
                  
                  
                  $
                  21
                  
                  
                  $
                  1
                  
                  
                  $
                  632


56


Condensed
      Consolidating Statement of Cash Flows
                    Three
      Months Ended March 31, 2008(in
      millions)
                  
                  Parent
                  
                  
                  Subsidiary
      Guarantor
                  
                  
                  Non-Guarantor
      Subsidiary
                  
                  
                  Other
                  
                  
                  Progress
      Energy, Inc.Net
      cash (used) provided by operating activities
                  
                  $
                  (55
                  )
                  
                  $
                  393
                  
                  
                  $
                  419
                  
                  
                  $
                  20
                  
                  
                  $
                  777Investing
      activitiesGross
      property additions
                  
                  
                  –
                  
                  
                  
                  (446
                  )
                  
                  
                  (173
                  )
                  
                  
                  1
                  
                  
                  
                  (618
                  )Nuclear
      fuel additions
                  
                  
                  –
                  
                  
                  
                  –
                  
                  
                  
                  (41
                  )
                  
                  
                  –
                  
                  
                  
                  (41
                  )Proceeds
      from sales of discontinued operations and other assets, net of cash
      divested
                  
                  
                  –
                  
                  
                  
                  94
                  
                  
                  
                  1
                  
                  
                  
                  –
                  
                  
                  
                  95Proceeds
      from sales of assets to affiliated companies
                  
                  
                  –
                  
                  
                  
                  8
                  
                  
                  
                  –
                  
                  
                  
                  (8
                  )
                  
                  
                  –Purchases
      of available-for-sale securities and other investments
                  
                  
                  –
                  
                  
                  
                  (247
                  )
                  
                  
                  (193
                  )
                  
                  
                  (48
                  )
                  
                  
                  (488
                  )Proceeds
      from available-for-sale securities and other investments
                  
                  
                  –
                  
                  
                  
                  247
                  
                  
                  
                  185
                  
                  
                  
                  41
                  
                  
                  
                  473Changes
      in advances to affiliated companies
                  
                  
                  122
                  
                  
                  
                  111
                  
                  
                  
                  (85
                  )
                  
                  
                  (148
                  )
                  
                  
                  –Contributions
      to consolidated subsidiaries
                  
                  
                  (97
                  )
                  
                  
                  –
                  
                  
                  
                  –
                  
                  
                  
                  97
                  
                  
                  
                  –Other
      investing activities
                  
                  
                  –
                  
                  
                  
                  14
                  
                  
                  
                  (5
                  )
                  
                  
                  (15
                  )
                  
                  
                  (6
                  )Net
      cash provided (used) by investing activities
                  
                  
                  25
                  
                  
                  
                  (219
                  )
                  
                  
                  (311
                  )
                  
                  
                  (80
                  )
                  
                  
                  (585
                  )Financing
      activitiesIssuance
      of common stock
                  
                  
                  20
                  
                  
                  
                  –
                  
                  
                  
                  –
                  
                  
                  
                  –
                  
                  
                  
                  20Dividends
      paid on common stock
                  
                  
                  (159
                  )
                  
                  
                  –
                  
                  
                  
                  –
                  
                  
                  
                  –
                  
                  
                  
                  (159
                  )Dividends
      paid to parent
                  
                  
                  –
                  
                  
                  
                  (3
                  )
                  
                  
                  –
                  
                  
                  
                  3
                  
                  
                  
                  –Payments
      of short-term debt with original maturities greater than 90
      days
                  
                  
                  (176
                  )
                  
                  
                  –
                  
                  
                  
                  –
                  
                  
                  
                  –
                  
                  
                  
                  (176
                  )Net
      increase in short-term debt
                  
                  
                  180
                  
                  
                  
                  –
                  
                  
                  
                  –
                  
                  
                  
                  –
                  
                  
                  
                  180Proceeds
      from issuance of long-term debt
                  
                  
                  –
                  
                  
                  
                  –
                  
                  
                  
                  322
                  
                  
                  
                  –
                  
                  
                  
                  322Retirement
      of long-term debt
                  
                  
                  –
                  
                  
                  
                  (80
                  )
                  
                  
                  –
                  
                  
                  
                  –
                  
                  
                  
                  (80
                  )Cash
      distributions to noncontrolling interests of consolidated
      subsidiaries
                  
                  
                  –
                  
                  
                  
                  (85
                  )
                  
                  
                  –
                  
                  
                  
                  –
                  
                  
                  
                  (85
                  )Changes
      in advances from affiliated companies
                  
                  
                  –
                  
                  
                  
                  (53
                  )
                  
                  
                  (154
                  )
                  
                  
                  207
                  
                  
                  
                  –Contributions
      from parent
                  
                  
                  –
                  
                  
                  
                  85
                  
                  
                  
                  13
                  
                  
                  
                  (98
                  )
                  
                  
                  –Other
      financing activities
                  
                  
                  (1
                  )
                  
                  
                  2
                  
                  
                  
                  (17
                  )
                  
                  
                  (53
                  )
                  
                  
                  (69
                  )Net
      cash (used) provided by financing activities
                  
                  
                  (136
                  )
                  
                  
                  (134
                  )
                  
                  
                  164
                  
                  
                  
                  59
                  
                  
                  
                  (47
                  )Net
      (decrease) increase in cash and cash equivalents
                  
                  
                  (166
                  )
                  
                  
                  40
                  
                  
                  
                  272
                  
                  
                  
                  (1
                  )
                  
                  
                  145Cash
      and cash equivalents at beginning of period
                  
                  
                  185
                  
                  
                  
                  43
                  
                  
                  
                  25
                  
                  
                  
                  2
                  
                  
                  
                  255Cash
      and cash equivalents at end of period
                  
                  $
                  19
                  
                  
                  $
                  83
                  
                  
                  $
                  297
                  
                  
                  $
                  1
                  
                  
                  $
                  400


57


ITEM
2.                      MANAGEMENT’S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS




The
following combined Management’s Discussion and Analysis of Financial Condition
and Results of Operations (MD&A) is separately filed by Progress Energy,
Inc. (Progress Energy), Carolina Power & Light Company d/b/a Progress Energy
Carolinas, Inc. (PEC) and Florida Power Corporation d/b/a Progress Energy
Florida, Inc. (PEF). As used in this report, Progress Energy, which includes
Progress Energy, Inc. holding company (the Parent) and its regulated and
nonregulated subsidiaries on a consolidated basis, is at times referred to as
“we,” “us” or “our.” When discussing Progress Energy’s financial information, it
necessarily includes the results of PEC and PEF (collectively, the Utilities).
The term “Progress Registrants” refers to each of the three separate
registrants: Progress Energy, PEC and PEF. Information contained herein relating
to PEC and PEF individually is filed by such company on its own behalf. Neither
of the Utilities makes any representation as to information related solely to
Progress Energy or the subsidiaries of Progress Energy other than
itself.




The
following MD&A contains forward-looking statements that involve estimates,
projections, goals, forecasts, assumptions, risks and uncertainties that could
cause actual results or outcomes to differ materially from those expressed in
the forward-looking statements. Please review “Safe Harbor for Forward-Looking
Statements” and Item 1A, “Risk Factors” found within Part II of this Form 10-Q
and Item 1A, “Risk Factors” to the Progress Registrant’s annual report on Form
10-K for the fiscal year ended December 31, 2008 (2008 Form 10-K) for a
discussion of the factors that may impact any such forward-looking statements
made herein.




Amounts
reported in the interim statements of income are not necessarily indicative of
amounts expected for the respective annual or future periods due to the effects
of weather variations and the timing of outages of electric generating units,
especially nuclear-fueled units, among other factors.




This
discussion should be read in conjunction with the accompanying financial
statements found elsewhere in this report and in conjunction with the 2008 Form
10-K.




PROGRESS
ENERGY




RESULTS OF
OPERATIONS




In this
section, earnings and the factors affecting earnings for the three months ended
March 31, 2009, are compared to the same period in 2008. The discussion begins
with a summarized overview of our consolidated earnings, which is followed by a
more detailed discussion and analysis by business segment.




Our
reportable operating business segments are PEC and PEF, which are primarily
engaged in the generation, transmission, distribution and sale of electricity in
portions of North Carolina and South Carolina, and Florida,
respectively.




Our
“Corporate and Other” segment primarily includes the operations of the Parent,
Progress Energy Service Company, LLC (PESC) and other miscellaneous nonregulated
businesses that do not separately meet the quantitative disclosure requirements
as a reportable business segment.




OVERVIEW




For the
quarter ended March 31, 2009, our net income attributable to controlling
interests was $182 million, or $0.66 per share, compared to net income
attributable to controlling interests of $209 million, or $0.80 per share, for
the same period in 2008. For the quarter ended March 31, 2009, our income from
continuing operations was $183 million compared to $153 million for the same
period in 2008. The increase in income from continuing operations as compared to
prior year was primarily due to:




·
            favorable
      weather at the Utilities;


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


·
            higher
      wholesale revenues at the Utilities;
and


·
            lower
      income tax expense resulting from the deduction related to nuclear
      decommissioning trust funds.




58




Offsetting
these items were:




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


·
            higher
      interest expense at PEF; and


·
            unfavorable
      net retail customer growth and usage at the
  Utilities.





Our
segments contributed the following profits or losses for the three months ended
March 31, 2009 and 2008:




Three Months Ended March 31,(in
      millions)
                      
                      2009
                      
                      
                      2008Business
      SegmentPEC
                      
                      $
                      127
                      
                      
                      $
                      122PEF
                      
                      
                      88
                      
                      
                      
                      66Total
      segment profit
                      
                      
                      215
                      
                      
                      
                      188Corporate
      and Other
                      
                      
                      (32
                      )
                      
                      
                      (35
                      )Income
      from continuing operations
                      
                      
                      183
                      
                      
                      
                      153Discontinued
      operations, net of tax
                      
                      
                      –
                      
                      
                      
                      61Net
      income attributable to noncontrolling interests, net of
tax
                      
                      
                      (1
                      )
                      
                      
                      (5
                      )Net
      income attributable to controlling interests
                      
                      $
                      182
                      
                      
                      $
                      209





PROGRESS
ENERGY CAROLINAS




PEC
contributed segment profits of $127 million and $122 million for the three
months ended March 31, 2009 and 2008, respectively. The increase in profits for
the three months ended March 31, 2009, compared to the same period in 2008, was
primarily due to lower North Carolina Clean Smokestacks Act (Clean Smokestacks
Act) amortization and the favorable impact of weather, partially offset by
higher O&M expenses and the unfavorable impact of tax
levelization.




The
revenue table that follows presents the total amount and percentage change of
revenues excluding fuel and other pass-through revenues. Revenues excluding fuel
and other pass-through revenues is defined as total electric revenues less fuel
and other pass-through revenues. We and PEC consider revenues excluding fuel and
other pass-through revenues a useful measure to evaluate PEC’s electric
operations because fuel and other pass-through revenues primarily represent the
recovery of fuel and a portion of purchased power expenses and other
pass-through expenses through cost-recovery clauses and, therefore, do not have
a material impact on earnings. We and PEC have included the analysis below as a
complement to the financial information we provide in accordance with accounting
principles generally accepted in the United States of America (GAAP). However,
revenues excluding fuel and other pass-through revenues is not defined under
GAAP, and the presentation may not be comparable to other companies’
presentation or more useful than the GAAP information provided elsewhere in this
report.




59




REVENUES




PEC’s
electric revenues for the three months ended March 31, 2009 and 2008, and the
amount and percentage change by customer class were as follows:




(in
      millions)
                  
                  Three
      Months Ended March 31,Customer
      Class
                  
                  2009
                  
                  
                  Change
                  
                  
                  %
      Change
                  
                  
                  2008Residential
                  
                  $
                  512
                  
                  
                  $
                  86
                  
                  
                  
                  20.2
                  
                  
                  $
                  426Commercial
                  
                  
                  290
                  
                  
                  
                  28
                  
                  
                  
                  10.7
                  
                  
                  
                  262Industrial
                  
                  
                  164
                  
                  
                  
                  (4
                  )
                  
                  
                  (2.4
                  )
                  
                  
                  168Governmental
                  
                  
                  26
                  
                  
                  
                  3
                  
                  
                  
                  13.0
                  
                  
                  
                  23Total
      retail revenues
                  
                  
                  992
                  
                  
                  
                  113
                  
                  
                  
                  12.9
                  
                  
                  
                  879Wholesale
                  
                  
                  193
                  
                  
                  
                  12
                  
                  
                  
                  6.6
                  
                  
                  
                  181Unbilled
                  
                  
                  (38
                  )
                  
                  
                  (21
                  )
                  
                  
                  –
                  
                  
                  
                  (17
                  )Miscellaneous
                  
                  
                  31
                  
                  
                  
                  7
                  
                  
                  
                  29.2
                  
                  
                  
                  24Total
      electric revenues
                  
                  
                  1,178
                  
                  
                  
                  111
                  
                  
                  
                  10.4
                  
                  
                  
                  1,067Less:
      Fuel and other pass-through revenues
                  
                  
                  (479
                  )
                  
                  
                  (92
                  )
                  
                  
                  –
                  
                  
                  
                  (387
                  )Revenues
      excluding fuel and other pass-through revenues
                  
                  $
                  699
                  
                  
                  $
                  19
                  
                  
                  
                  2.8
                  
                  
                  $
                  680





PEC’s
revenues, excluding fuel and other pass-through revenues of $479 million and
$387 million for the three months ended March 31, 2009 and 2008, respectively,
increased $19 million. The increase in revenues was primarily due to $13 million
favorable impact of weather, $7 million higher miscellaneous revenues and $4
million higher wholesale revenues, excluding fuel and other pass-through
revenues, partially offset by $5 million unfavorable impact of net retail
customer growth and usage. The favorable impact of weather was primarily driven
by 8 percent higher heating degree days than 2008. Heating degree days were
comparable to normal in 2009 and 7 percent lower than normal in 2008.
Higher miscellaneous revenues were primarily due to higher transmission revenues
resulting from the Open Access Transmission Tariff rates that went into effect
on July 1, 2008. Higher wholesale revenues were primarily due to contracts with
two major customers driven by weather-related capacity increases, partially
offset by lower excess generation sales due to unfavorable market dynamics
resulting from normal weather in 2009 and higher relative fuel costs. The
unfavorable impact of net retail customer growth and usage was driven by a
decrease in the average usage per retail customer, partially offset by a net
18,000 increase in the average number of customers for the three months ended
March 31, 2009, compared to the same period in 2008.




PEC’s
electric energy sales for the three months ended March 31, 2009 and 2008, and
the amount and percentage change by customer class were as follows:




(in
      millions of kWh)
                  
                  Three
      Months Ended March 31,Customer
      Class
                  
                  2009
                  
                  
                  Change
                  
                  
                  %
      Change
                  
                  
                  2008Residential
                  
                  
                  5,138
                  
                  
                  
                  460
                  
                  
                  
                  9.8
                  
                  
                  
                  4,678Commercial
                  
                  
                  3,315
                  
                  
                  
                  37
                  
                  
                  
                  1.1
                  
                  
                  
                  3,278Industrial
                  
                  
                  2,420
                  
                  
                  
                  (352
                  )
                  
                  
                  (12.7
                  )
                  
                  
                  2,772Governmental
                  
                  
                  343
                  
                  
                  
                  10
                  
                  
                  
                  3.0
                  
                  
                  
                  333Total
      retail energy sales
                  
                  
                  11,216
                  
                  
                  
                  155
                  
                  
                  
                  1.4
                  
                  
                  
                  11,061Wholesale
                  
                  
                  3,676
                  
                  
                  
                  (96
                  )
                  
                  
                  (2.5
                  )
                  
                  
                  3,772Unbilled
                  
                  
                  (464
                  )
                  
                  
                  (223
                  )
                  
                  
                  –
                  
                  
                  
                  (241
                  )Total
      kWh sales
                  
                  
                  14,428
                  
                  
                  
                  (164
                  )
                  
                  
                  (1.1
                  )
                  
                  
                  14,592





Wholesale
revenues increased for the three months ended March 31, 2009, despite a decrease
in wholesale kilowatt-hours (kWh) sales for the same period primarily due to the
impact of increased fuel revenues as a result of higher energy costs. Wholesale
kWh sales decreased for the three months ended March 31, 2009, primarily due to
decreased excess generation sales resulting from unfavorable market
dynamics.




PEC has
experienced some decline in the rate of residential and commercial sales growth
due to the current recession in the United States. Additionally, PEC’s
industrial kWh sales have decreased 12.4 percent from 2008, but industrial
revenues have only decreased 12.7 percent due in part to the demand charges
component of industrial




60




revenues. Many of
the manufacturers in PEC’s service territory have been adversely impacted by the
recession, and we expect continued industrial sales weakness until the broader
economy recovers. We cannot predict how long the recession may last or the
extent to which it may impact revenues. In the future, PEC’s customer usage
could be impacted by customer response to energy-efficiency programs and to
increased rates.




EXPENSES




Fuel and Purchased
Power




Fuel and
purchased power costs represent the costs of generation, which include fuel
purchases for generation, as well as energy purchased in the market to meet
customer load. Fuel and a portion of purchased power expenses are recovered
primarily through cost-recovery clauses, and as such, changes in these expenses
do not have a material impact on earnings. The difference between fuel and
purchased power costs incurred and associated fuel revenues that are subject to
recovery is deferred for future collection from or refund to
customers.




Fuel and
purchased power expenses were $499 million for the three months ended March 31,
2009, which represents a $94 million increase compared to the same period in
2008. Fuel used in electric generation increased $86 million to $442 million
primarily due to the $65 million impact of higher coal prices and $16 million
higher deferred fuel expense. The increase in deferred fuel expense was
primarily due to the implementation of new fuel rates in North Carolina.
Purchased power expense increased $8 million to $57 million compared to the same
period in 2008 primarily due to an increase in interchange purchases of $13
million and purchases from renewable energy sources of $3 million, partially
offset by lower cogeneration of $7 million. The increase in interchange
purchases was primarily due to timing of plant outages in 2009.




Operation and
Maintenance




O&M
expense was $259 million for the three months ended March 31, 2009, which
represents an $11 million increase compared to the same period in 2008. This
increase is primarily due to $14 million higher nuclear plant outage and
maintenance costs driven by the timing of outages and $5 million lower nuclear
insurance refund, partially offset by $8 million lower emission expense
primarily due to sales of nitrogen oxides (NOx) emission
allowances.





Depreciation, Amortization
and Accretion




Depreciation,
amortization and accretion expense was $117 million for the three months ended
March 31, 2009, which represents a $9 million decrease compared to the same
period in 2008. Depreciation, amortization and accretion expense decreased
primarily due to $15 million lower Clean Smokestacks Act amortization, partially
offset by the $4 million impact of depreciable asset base increases. In
accordance with a regulatory order, PEC ceased to amortize Clean Smokestacks Act
compliance costs, but will record depreciation over the useful life of the
assets.




Taxes Other Than on
Income




Taxes
other than on income was $54 million for the three months ended March 31, 2009,
which represents a $4 million increase compared to the same period in 2008. This
increase is primarily due to a $2 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,
Net




Total
other income, net was $4 million for the three months ended March 31, 2009,
which represents a $5 million decrease compared to the same period in 2008. This
decrease is primarily due to seasonal losses on a balanced billing program of $4
million, lower interest income of $3 million and investment losses of $2
million, partially offset by favorable AFUDC equity of $5 million. The favorable
AFUDC equity is related to increased eligible construction project costs, which
we expect to continue for the remainder of 2009.




61




Income Tax
Expense




Income
tax expense increased $1 million for the three months ended March 31, 2009, as
compared to the same period in 2008, primarily due to the $5 million impact of
tax levelization, discussed below, offset by the $5 million favorable tax
benefit related to a deduction triggered by the transfer of previously funded
amounts from nonqualified nuclear decommissioning trusts to qualified nuclear
decommissioning trusts. 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 increased by $2 million for the
three months ended March 31, 2009 compared to a decrease of $3 million for the
three months ended March 31, 2008, in order to maintain an effective tax rate
consistent with the estimated annual rate. Fluctuations in estimated annual
earnings and the timing of various permanent items of income or deduction can
cause fluctuations in the effective tax rate for interim periods. Therefore,
this adjustment will vary each quarter, but will have no effect on net income
for the year.




PROGRESS
ENERGY FLORIDA




PEF
contributed segment profits of $88 million and $66 million for the three months
ended March 31, 2009 and 2008, respectively. The increase in profits for the
three months ended March 31, 2009, compared to the same period in 2008, was
primarily due to favorable AFUDC equity, lower income tax expense resulting from
the deduction related to nuclear decommissioning trust funds, higher wholesale
revenues and the favorable impact of weather, partially offset by higher
interest expense, the unfavorable impact of net retail customer growth and
usage, and higher O&M expenses.




The
revenue table that follows presents the total amount and percentage change of
revenues excluding fuel and other pass-through revenues. Revenues excluding fuel
and other pass-through revenues is defined as total electric revenues less fuel
and other pass-through revenues. We and PEF consider revenues excluding fuel and
other pass-through revenues a useful measure to evaluate PEF’s electric
operations because fuel and other pass-through revenues primarily represent the
recovery of fuel, purchased power and other pass-through expenses through
cost-recovery clauses and, therefore, do not have a material impact on earnings.
We and PEF have included the analysis below as a complement to the financial
information we provide in accordance with GAAP. However, revenues excluding fuel
and other pass-through revenues is not defined under GAAP, and the presentation
may not be comparable to other companies’ presentation or more useful than the
GAAP information provided elsewhere in this report.




REVENUES




PEF’s
electric revenues for the three months ended March 31, 2009 and 2008, and the
amount and percentage change by customer class were as follows:




(in
      millions)
                    
                    Three
      Months Ended March 31,Customer
      Class
                    
                    2009
                    
                    
                    Change
                    
                    
                    %
      Change
                    
                    
                    2008Residential
                    
                    $
                    625
                    
                    
                    $
                    161
                    
                    
                    
                    34.7
                    
                    
                    $
                    464Commercial
                    
                    
                    304
                    
                    
                    
                    62
                    
                    
                    
                    25.6
                    
                    
                    
                    242Industrial
                    
                    
                    84
                    
                    
                    
                    15
                    
                    
                    
                    21.7
                    
                    
                    
                    69Governmental
                    
                    
                    83
                    
                    
                    
                    16
                    
                    
                    
                    23.9
                    
                    
                    
                    67Total
      retail revenues
                    
                    
                    1,096
                    
                    
                    
                    254
                    
                    
                    
                    30.2
                    
                    
                    
                    842Wholesale
                    
                    
                    117
                    
                    
                    
                    14
                    
                    
                    
                    13.6
                    
                    
                    
                    103Unbilled
                    
                    
                    5
                    
                    
                    
                    (1
                    )
                    
                    
                    –
                    
                    
                    
                    6Miscellaneous
                    
                    
                    44
                    
                    
                    
                    (1
                    )
                    
                    
                    (2.2
                    )
                    
                    
                    45Total
      electric revenues
                    
                    
                    1,262
                    
                    
                    
                    266
                    
                    
                    
                    26.7
                    
                    
                    
                    996Less:
      Fuel and other pass-through revenues
                    
                    
                    (853
                    )
                    
                    
                    (245
                    )
                    
                    
                    –
                    
                    
                    
                    (608
                    )Revenues
      excluding fuel and other pass-through revenues
                    
                    $
                    409
                    
                    
                    $
                    21
                    
                    
                    
                    5.4
                    
                    
                    $
                    388





PEF’s
revenues, excluding fuel and other pass-through revenues of $853 million and
$608 million for the three months ended March 31, 2009 and 2008, respectively,
increased $21 million. The increase in revenues was primarily due to the $17
million favorable impact of weather and $17 million higher wholesale revenues,
excluding fuel and other pass-through revenues, partially offset by the $11
million unfavorable impact of net retail customer growth and usage. The
favorable impact of weather was primarily driven by 41 percent higher heating
degree days




62




than
2008. Heating degree days were comparable to normal in 2009 and 27 percent lower
than normal in 2008. Wholesale revenues increased primarily due to new and
amended contracts that were not in effect in the same period in
2008.




The
current recession in the United States has contributed to a slowdown in customer
growth and usage in PEF’s service territory. In addition to lower average usage
per customer, PEF’s average number of customer for the three months ended March
31, 2009, compared to the same period in 2008, decreased a net 8,000 customers.
In comparison, PEF’s average number of customers for the three months ended
March 31, 2008, compared to the same period in 2007, increased a net 7,000
customers. We cannot predict how long the recession may last or the extent to
which it may impact revenues. In the future, PEF’s customer usage could be
impacted by customer response to energy-efficiency programs and to increased
rates.




PEF’s
electric energy sales for the three months ended March 31, 2009 and 2008, and
the amount and percentage change by customer class were as follows:




(in
      millions of kWh)
                  
                  Three
      Months Ended March 31,Customer
      Class
                  
                  2009
                  
                  
                  Change
                  
                  
                  %
      Change
                  
                  
                  2008Residential
                  
                  
                  4,287
                  
                  
                  
                  282
                  
                  
                  
                  7.0
                  
                  
                  
                  4,005Commercial
                  
                  
                  2,554
                  
                  
                  
                  (107
                  )
                  
                  
                  (4.0
                  )
                  
                  
                  2,661Industrial
                  
                  
                  791
                  
                  
                  
                  (74
                  )
                  
                  
                  (8.6
                  )
                  
                  
                  865Governmental
                  
                  
                  732
                  
                  
                  
                  (35
                  )
                  
                  
                  (4.6
                  )
                  
                  
                  767Total
      retail energy sales
                  
                  
                  8,364
                  
                  
                  
                  66
                  
                  
                  
                  0.8
                  
                  
                  
                  8,298Wholesale
                  
                  
                  1,207
                  
                  
                  
                  (183
                  )
                  
                  
                  (13.2
                  )
                  
                  
                  1,390Unbilled
                  
                  
                  (170
                  )
                  
                  
                  (390
                  )
                  
                  
                  –
                  
                  
                  
                  220Total
      kWh sales
                  
                  
                  9,401
                  
                  
                  
                  (507
                  )
                  
                  
                  (5.1
                  )
                  
                  
                  9,908





Commercial,
industrial and governmental revenues increased for the three months ended March
31, 2009, despite a decrease in kWh sales for the same period primarily due to
the impact of increased fuel revenues as a result of higher fuel rates and the
recovery of nuclear costs in accordance with a regulatory order issued in late
2008.




Wholesale
revenues increased for the three months ended March 31, 2009, despite a decrease
in kWh sales for the same period primarily due to peak demand charges and
increased fixed capacity.





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 $672 million for the three months ended March 31,
2009, which represents a $148 million increase compared to the same period in
2008. Fuel used in electric generation increased $171 million to $512 million
compared to the same period in 2008. This increase was primarily due to higher
deferred fuel expense of $93 million driven by the implementation of new fuel
rates to collect fuel costs from customers that had been previously
under-recovered and increased current year fuel costs of $78 million. The
increase in current year fuel costs was primarily due to increased fuel prices
and a change in generation mix. Purchased power expense decreased $23 million to
$160 million compared to the same period in 2008. This decrease was primarily
due to a decrease in interchange purchases of $19 million resulting from lower
system requirements.




Operation and
Maintenance




O&M
expense was $202 million for the three months ended March 31, 2009, which
represents a $1 million decrease when compared to the same period in 2008.
O&M expense decreased $26 million due to the storm damage reserve
replenishment surcharge that ended in July 2008, partially offset by $16 million
higher environmental cost recovery




63




(ECRC) costs due
to increased rates resulting primarily from the recovery of emission allowances
and higher pension costs of $9 million resulting from revised actuarial
estimates. The replenishment of storm damage reserves and ECRC expenses are
recovered through cost-recovery clauses and, therefore, have no material impact
on earnings. In aggregate, O&M expenses recoverable through base rates
increased $6 million compared to the same period in 2008.




Depreciation, Amortization
and Accretion




Depreciation,
amortization and accretion expense was $160 million for the three months ended
March 31, 2009, which represents an $84 million increase compared to the same
period in 2008. Depreciation, amortization and accretion expense increased
primarily due to $80 million higher nuclear cost-recovery amortization which
began in January 2009 in accordance with a 2008 regulatory order. The nuclear
cost-recovery amortization is recovered through a cost-recovery clause and,
therefore, has no material impact on earnings. In aggregate, depreciation,
amortization and accretion expenses recoverable through base rates increased $2
million compared to the same period in 2008.




Taxes Other Than on
Income




Taxes
other than on income was $88 million for the three months ended March 31, 2009,
which represents a $17 million increase compared to the same period in 2008.
This increase is primarily due to a $13 million increase in gross receipts and
franchise taxes due to higher retail revenues. Gross receipts and franchise
taxes are collected from customers and recorded as revenues and then remitted to
the applicable taxing authority. Therefore, these taxes have no material impact
on earnings.




Total Other Income,
Net




Total
other income, net was $31 million for the three months ended March 31, 2009,
which represents a $13 million increase compared to the same period in 2008.
This increase was primarily due to $11 million favorable AFUDC equity related to
eligible construction project costs.




Total Interest Charges,
net




Total
interest charges, net was $58 million for the three months ended March 31, 2009,
which represents a $14 million increase compared to the same period in 2008.
This increase was primarily due to $15 million higher interest as a result of
higher average debt outstanding, partially offset by $3 million favorable AFUDC
debt related to eligible construction project costs.




Income Tax
Expense




Income
tax expense decreased $5 million for the three months ended March 31, 2009,
compared to the same period in 2008, primarily due to the $11 million impact of
the favorable tax benefit related to a deduction triggered by the transfer of
previously funded amounts from the nonqualified nuclear decommissioning trust to
the qualified nuclear decommissioning trust, and the $4 million impact of the
increase in AFUDC equity discussed above, partially offset by the $6 million tax
impact of higher pre-tax earnings and the $2 million impact of tax levelization.
AFUDC equity is excluded from the calculation of income tax expense. GAAP
requires companies to apply a levelized effective tax rate to interim periods
that is consistent with the estimated annual effective tax rate. PEF’s income
tax expense was increased by $3 million for the three months ended March 31,
2009 compared to $1 million for the three months ended March 31, 2008, in order
to maintain an effective tax rate consistent with the estimated annual rate.
Fluctuations in estimated annual earnings and the timing of various permanent
items of income or deduction can cause fluctuations in the effective tax rate
for interim periods. Therefore, this adjustment will vary each quarter, but will
have no effect on net income for the year.




64




CORPORATE
AND OTHER




The
Corporate and Other segment primarily includes the operations of the Parent,
PESC and other miscellaneous nonregulated businesses that do not separately meet
the quantitative disclosure requirements as a reportable segment. Corporate and
Other expense is summarized below:




Three
      Months Ended March 31,(in
      millions)
                  
                  2009
                  
                  
                  2008Other
      interest expense
                  
                  $
                  (55
                  )
                  
                  $
                  (54
                  )Contingent
      value obligations
                  
                  
                  7
                  
                  
                  
                  –Tax
      levelization
                  
                  
                  (1
                  )
                  
                  
                  (1
                  )Other
      income tax benefit
                  
                  
                  10
                  
                  
                  
                  17Continuing
      income attributable to noncontrolling interests, net of
tax
                  
                  
                  1
                  
                  
                  
                  4Other
                  
                  
                  6
                  
                  
                  
                  (1
                  )Corporate
      and Other after-tax expense
                  
                  $
                  (32
                  )
                  
                  $
                  (35
                  )





At March
31, 2009 and 2008, the contingent value obligations (CVOs) had fair values of
approximately $27 million and $34 million, respectively. We recorded an
unrealized gain of $7 million for the three months ended March 31, 2009, and no
adjustment for the three months ended March 31, 2008, to record the changes in
fair value of the CVOs, which had average unit prices of $0.28 and $0.35 at
March 31, 2009 and 2008, respectively. See Note 15 in the 2008 Form 10-K for
further information.




Other
income tax benefit decreased $7 million for the three months ended March 31,
2009, compared to the same period in 2008, primarily due to the tax impact of
employee benefits as well as the unfavorable impact on the Corporate tax
position resulting from the deductions taken by the Utilities related to nuclear
decommissioning trust funds (See “Progress Energy Carolinas – Income Tax
Expense” and “Progress Energy Florida – Income Tax Expense”).




Other
increased $7 million for the three months ended March 31, 2009, compared to the
same period in 2008, primarily due to lower workers' compensation expense,
higher investment gains of certain employee benefit trusts resulting from market
conditions and higher interest income.




DISCONTINUED
OPERATIONS




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




TERMINALS
OPERATIONS AND SYNTHETIC FUELS BUSINESSES




On March
7, 2008, we sold coal terminals and docks in West Virginia and Kentucky
(Terminals) for $71 million in gross cash proceeds. The coal terminals had a
total annual capacity in excess of 40 million tons for transloading, blending
and storing coal and other commodities. Proceeds from the sale were used for
general corporate purposes. During the three months ended March 31, 2008, we
recorded an after-tax gain of $46 million on the sale of these
assets.




Prior to
2008, we had substantial operations associated with the production of coal-based
solid synthetic fuels (Synthetic Fuels). The production and sale of these
products qualified for federal income tax credits so long as certain
requirements were satisfied. As a result of the expiration of the tax credit
program, all of our synthetic fuels businesses were abandoned and all operations
ceased as of December 31, 2007.




Terminals
and the synthetic fuels businesses collectively generated net earnings from
discontinued operations attributable to controlling interests of $12 million for
the three months ended March 31, 2008.




COAL
MINING BUSINESSES




On March
7, 2008, we sold the remaining operations of Progress Fuels Corporation
(Progress Fuels) subsidiaries engaged in the coal mining business for gross cash
proceeds of $23 million. Proceeds from the sale were used for general corporate
purposes. These assets included Powell Mountain Coal Co. and Dulcimer Land Co.,
which




65




consisted
of approximately 30,000 acres in Lee County, Va., and Harlan County, Ky. As a
result of the sale, during the three months ended March 31, 2008, we recorded an
after-tax gain of $7 million on the sale of these assets.




Net
losses from discontinued operations for Coal Mining, excluding gain on disposal,
were $6 million for the three months ended March 31, 2008.





OTHER
DIVERSIFIED BUSINESSES





Also
included in discontinued operations in 2008 are amounts related to adjustments
of our prior sales of other diversified businesses, primarily our natural gas
drilling and production business (Gas) and Progress Rail Services Corporation
(Progress Rail). These adjustments are mainly due to the finalization of working
capital and in connection with guarantees and indemnifications provided by
Progress Fuels and Progress Energy for certain legal, tax and environmental
matters (See Note 15B). The ultimate resolution of these matters could result in
additional adjustments in future periods. For the three months ended March 31,
2008, we recorded additional gains of $1 million, net of tax.




LIQUIDITY AND CAPITAL
RESOURCES




OVERVIEW




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




The
majority of our operating costs are related to the Utilities. Most of these
costs are recovered from ratepayers in accordance with various rate plans. We
are allowed to recover certain fuel, purchased power and other costs incurred by
PEC and PEF through their respective recovery clauses. The types of costs
recovered through clauses vary by jurisdiction. Fuel price volatility can lead
to over- or under-recovery of fuel costs, as changes in fuel prices are not
immediately reflected in fuel surcharges due to regulatory lag in setting the
surcharges. As a result, fuel price volatility can be both a source of and a use
of liquidity resources, depending on what phase of the cycle of price volatility
we are experiencing. Changes in the Utilities’ fuel and purchased power costs
may affect the timing of cash flows, but not materially affect net
income.




As a
registered holding company, we are subject to regulation by the Federal Energy
Regulatory Commission (FERC) for, among other things, the establishment of
intercompany extensions of credit (utility and non-utility money pools). Our
subsidiaries participate in internal money pools, operated by Progress Energy,
to more effectively utilize cash resources and reduce outside short-term
borrowings. The utility money pool allows the Utilities to lend to and borrow
from each other. The non-utility money pool allows our nonregulated 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.




The
Parent is a holding company and, as such, has no revenue-generating operations
of its own. The primary cash needs at the Parent level are our common stock
dividend, interest and principal payments on the Parent’s $3.35 billion of
senior unsecured debt and potentially funding the Utilities’ capital
expenditures through equity contributions. The Parent’s ability to meet these
needs is typically funded with dividends from the Utilities generated from their
earnings and cash flows, and to a lesser extent, dividends from other
subsidiaries; repayment of funds due to the Parent by its subsidiaries; the
Parent’s bank facility; and/or the Parent’s ability to access the short- and
long-term debt and equity capital markets. In recent years, rather than paying
dividends to the Parent, the Utilities, to a large extent, have retained their
free cash flow to fund their capital expenditures. The Utilities did not pay
dividends to the Parent in 2008. In the first quarter of 2009, PEC paid
dividends of $200 million to the Parent, and PEF received a $155 million equity
contribution from the Parent. There are a number of factors that impact the
Utilities’ decision or ability to pay dividends to the Parent or to seek equity
contributions from the Parent, including capital expenditure decisions and the
timing of recovery of fuel and other pass-through costs. Therefore, we cannot
predict the level of dividends or equity contributions between the Utilities and
the Parent from year-to-year. We do not currently expect changes to the Parent’s
common stock dividend policy.




66




Cash from
operations, commercial paper issuance, borrowings under our credit facilities,
long-term debt financings, equity offerings, and limited ongoing sales of common
stock from our Investor Plus Stock Purchase Plan, employee benefit and stock
option plans are expected to fund capital expenditures and common stock
dividends for 2009. For the fiscal year 2009, we expect to realize approximately
$600 million in the aggregate from the sale of stock through marketed and
ongoing equity sales (see discussion that follows under “Financing
Activities”).




We have
addressed the challenges presented by current financial market conditions and
will continue to monitor the credit markets to maintain an appropriate level of
liquidity. Despite the tightened credit market that began with the extreme
market turmoil in the third quarter of 2008, we have been able to issue
additional equity and short- and long-term debt.




As shown
in the table that follows, we have a number of financial institutions that
support our combined $2.030 billion revolving credit facilities for the Parent,
PEC and PEF, thereby limiting our dependence on any one institution. The credit
facilities serve as back-ups to our commercial paper programs. To the extent
amounts are reserved for commercial paper or letters of credit outstanding, they
are not available for additional borrowings. At March 31, 2009, the Parent had
$500 million of outstanding borrowings under its credit facility. In addition,
at March 31, 2009, PEF had an outstanding commercial paper balance of $130
million and the Parent had issued $29 million of letters of credit, which were
supported by the revolving credit agreement (RCA). Based on these amounts
outstanding at March 31, 2009, $1.371 billion was available for additional
borrowings under our combined revolving credit facilities.




(in
      millions)
                  
                  Total
      CommitmentCredit
      Provider
                  
                  Progress
      Energy
                  
                  
                  Parent
                  
                  
                  PEC
                  
                  
                  PEFJPMorgan
      Chase Bank, N.A.
                  
                  $
                  225.0
                  
                  
                  $
                  141.0
                  
                  
                  $
                  44.0
                  
                  
                  $
                  40.0Bank
      of Tokyo-Mitsubishi UFJ, Ltd., New York Branch
                  
                  
                  200.0
                  
                  
                  
                  95.0
                  
                  
                  
                  45.0
                  
                  
                  
                  60.0Barclays
      Bank PLC
                  
                  
                  190.5
                  
                  
                  
                  100.0
                  
                  
                  
                  20.5
                  
                  
                  
                  70.0Bank
      of America, N.A.
                  
                  
                  190.0
                  
                  
                  
                  98.0
                  
                  
                  
                  22.0
                  
                  
                  
                  70.0Citibank,
      N.A.
                  
                  
                  180.0
                  
                  
                  
                  111.0
                  
                  
                  
                  34.0
                  
                  
                  
                  35.0Wachovia
      Bank, N.A.
                  
                  
                  175.5
                  
                  
                  
                  53.0
                  
                  
                  
                  82.5
                  
                  
                  
                  40.0Royal
      Bank of Scotland plc
                  
                  
                  169.0
                  
                  
                  
                  92.0
                  
                  
                  
                  77.0
                  
                  
                  
                  –The
      Bank of New York Mellon
                  
                  
                  120.0
                  
                  
                  
                  35.0
                  
                  
                  
                  40.0
                  
                  
                  
                  45.0SunTrust
      Bank
                  
                  
                  115.0
                  
                  
                  
                  50.0
                  
                  
                  
                  20.0
                  
                  
                  
                  45.0Morgan
      Stanley Bank. NA
                  
                  
                  100.0
                  
                  
                  
                  50.0
                  
                  
                  
                  50.0
                  
                  
                  
                  –William
      Street Commitment Corporation
                  
                  
                  100.0
                  
                  
                  
                  100.0
                  
                  
                  
                  –
                  
                  
                  
                  –Deutsche
      Bank AG, New York Branch
                  
                  
                  95.0
                  
                  
                  
                  50.0
                  
                  
                  
                  –
                  
                  
                  
                  45.0UBS
      Loan Finance LLC
                  
                  
                  80.0
                  
                  
                  
                  80.0
                  
                  
                  
                  –
                  
                  
                  
                  –BNP
      Paribas
                  
                  
                  50.0
                  
                  
                  
                  50.0
                  
                  
                  
                  –
                  
                  
                  
                  –Branch
      Banking & Trust Co.
                  
                  
                  25.0
                  
                  
                  
                  25.0
                  
                  
                  
                  –
                  
                  
                  
                  –First
      Tennessee Bank N.A.
                  
                  
                  15.0
                  
                  
                  
                  –
                  
                  
                  
                  15.0
                  
                  
                  
                  –Total
      commitment
                  
                  $
                  2,030.0
                  
                  
                  $
                  1,130.0
                  
                  
                  $
                  450.0
                  
                  
                  $
                  450.0





At March
31, 2009, PEC and PEF had limited counterparty mark-to-market exposure for
financial commodity hedges (primarily gas and oil hedges) due to spreading our
concentration risk over a number of counterparties. In the event of default by a
counterparty, the exposure in the transaction is the cost of replacing the
agreements at current market rates. At March 31, 2009, the majority of the
Utilities’ open financial commodity hedges were in net mark-to-market liability
positions. See Note 11A for additional information with regard to our commodity
derivatives.




At March
31, 2009, we had limited mark-to-market exposure to certain financial
institutions under pay-fixed forward starting swaps to hedge cash flow risk with
regard to future financing transactions for each of the Parent, PEC and PEF. In
the event of default by a counterparty, the exposure in the transaction is the
cost of replacing the agreements at current market rates. At March 31, 2009, the
Parent’s, PEC’s and PEF’s mark-to-market positions were not material. See Note
11B for additional information with regard to our interest rate
derivatives.




67




Our
pension trust funds and nuclear decommissioning trust funds are managed by a
number of financial institutions, and the assets being managed are diversified
in order to limit concentration risk in any one institution or business
sector.




We
believe our internal and external liquidity resources will be sufficient to fund
our current business plans. Risk factors associated with credit facilities and
credit ratings are discussed below and in Item 1A, “Risk Factors” in the 2008
Form 10-K.




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




HISTORICAL
FOR 2009 AS COMPARED TO 2008




CASH
FLOWS FROM OPERATIONS




Net cash
provided by operating activities decreased $382 million for the three months
ended March 31, 2009, when compared to the corresponding period in the prior
year. The decrease was primarily due to a $385 million decrease from
receivables; a $216 million decrease resulting from cash collateral posted with
counterparties, primarily by PEF due to the significant decline in natural gas
prices; and a $155 million decrease from accounts payable, primarily driven by
the timing of PEF’s payments to vendors and higher payments for fuel purchases
due to increased fuel costs in 2009. The change in receivables was primarily
driven by the 2008 settlement of $247 million of derivative receivables largely
related to derivative contracts for our former synthetic fuels businesses and
increases in accounts receivable at the Utilities in 2009 driven by higher
revenues. These impacts were partially offset by a $123 million increase from
income taxes, net primarily driven by the receipt of a $70 million federal
income tax refund at PEC; a $108 million decrease in collateral held in 2008
associated with the synthetic fuels derivative contracts discussed above; a $104
million increase in the recovery of deferred fuel costs due to higher fuel
rates, primarily at PEF; and an $80 million increase in the recovery of nuclear
construction costs under Florida’s nuclear cost-recovery rule at
PEF.




INVESTING
ACTIVITIES




Net cash
used by investing activities increased by $106 million for the three months
ended March 31, 2009, when compared to the corresponding period in the prior
year. This increase was primarily due to $95 million in proceeds received in
2008 from sales of discontinued operations and other assets, net of cash
divested and a $21 million increase in 2009 in capital expenditures for gross
property additions, primarily at PEF. During 2008, proceeds from sales of
discontinued operations and other assets primarily included proceeds of $94
million from the sale of Terminals and Coal Mining (See Notes 3A and
3B).




FINANCING
ACTIVITIES




Net cash
provided by financing activities increased by $795 million for the three months
ended March 31, 2009, when compared to the corresponding period in the prior
year. The increase was primarily due to a $1.016 billion increase in proceeds
from long-term debt issuances, net due to PEC’s $600 million issuance and the
Parent’s $750 million issuance in 2009 compared to PEC’s $325 million issuance
in 2008; a $525 million increase from the issuance of common stock, primarily
related to the Parent’s January 2009 common stock offering; and a $147 million
decrease in payments on short-term debt compared to 2008. These impacts were
partially offset by a $670 million decrease in short-term indebtedness,
primarily driven by commercial paper repayments and the Parent’s $100 million
repayment of borrowings outstanding under its RCA and a $320 million increase in
long-term debt retirements, primarily related to PEC’s $400 million March 1,
2009 retirement. A discussion of our 2009 financing activities
follows.




On
January 12, 2009, the Parent issued 14.4 million shares of common stock at a
public offering price of $37.50 per share, which are included in the 15.5
million shares discussed below. Net proceeds from this offering were $523
million. On February 3, 2009, we used $100 million of the proceeds to reduce the
Parent’s $600 million RCA balance outstanding at December 31, 2008, and the
remainder was used for general corporate purposes. We will continue to monitor
the commercial paper and short-term credit markets to determine when to repay
the remaining $500 million outstanding balance of the RCA loan, while
maintaining an appropriate level of liquidity.




68




On
January 15, 2009, PEC issued $600 million of First Mortgage Bonds, 5.30% Series
due 2019. A portion of the proceeds was used to repay the maturity of PEC’s $400
million 5.95% Senior Notes, due March 1, 2009. The remaining proceeds were used
to repay PEC’s outstanding short-term debt and for general corporate
purposes.




On March
19, 2009, the Parent issued an aggregate $750 million of Senior Notes consisting
of $300 million of 6.05% Senior Notes due 2014 and $450 million of 7.05% Senior
Notes due 2019. A portion of the proceeds was used to fund PEF’s capital
expenditures through an equity contribution. The remaining proceeds will be used
for general corporate purposes.




At
December 31, 2008, we had 500 million shares of common stock authorized under
our charter, of which 264 million shares were outstanding. For the three months
ended March 31, 2009 and 2008, respectively, we issued approximately 15.5
million shares and 1.0 million shares of common stock resulting in approximately
$545 million and $20 million in net proceeds. Included in these amounts were
approximately 0.6 million shares and 0.4 million shares for net proceeds of
approximately $22 million and $19 million, respectively, to meet the
requirements of the Progress Energy 401(k) Savings and Stock Ownership Plan and
the Investor Plus Stock Purchase Plan.




FUTURE
LIQUIDITY AND CAPITAL RESOURCES




At March
31, 2009, there were no material changes in our “Capital Expenditures,” “Other
Cash Needs,” “Credit Facilities,” or “Credit Rating Matters” as compared to
those discussed under LIQUIDITY AND CAPITAL RESOURCES in Item 7 to the 2008 Form
10-K, other than as described below and under “Credit Rating Matters”,
“Regulatory Matters and Recovery of Costs” and “Financing
Activities.”




The
Utilities produce substantially all of our consolidated cash from operations. We
anticipate that the Utilities will continue to produce substantially all of the
consolidated cash flows from operations over the next several years. Our
discontinued synthetic fuels operations historically produced significant net
earnings from the generation of tax credits (See “Other Matters – Synthetic
Fuels Tax Credits”). A portion of these tax credits has yet to be realized in
cash due to the difference in timing of when tax credits are recognized for
financial reporting purposes and realized for tax purposes. At March 31, 2009,
we have carried forward $847 million of deferred tax credits. Realization of
these tax credits is dependent upon our future taxable income, which is expected
to be generated primarily by the Utilities.




We expect
to be able to meet our future liquidity needs through cash from operations,
commercial paper issuance, availability under our credit facilities, long-term
debt financings and equity offerings. We may also use periodic ongoing sales of
common stock from our Investor Plus Stock Purchase Plan and employee benefit and
stock option plans to meet our liquidity requirements.




We issue
commercial paper to meet short-term liquidity needs. As a result of financial
and economic conditions in 2008, the short-term credit markets tightened,
resulting in volatility in commercial paper durations and interest rates. In
November 2008, the Parent borrowed $600 million under its RCA to reduce rollover
risk in the commercial paper markets. A portion of the RCA was repaid with
proceeds from the January 2009 equity issuance, and we will continue to monitor
the commercial paper and short-term credit markets to determine when to repay
the remaining balance of the RCA loan, while maintaining an appropriate level of
liquidity. If liquidity conditions deteriorate further and negatively impact the
commercial paper market, we will need to evaluate other, potentially more
expensive, options for meeting our short-term liquidity needs, which may include
extending the term and amount of our borrowings under the Parent’s RCA, issuing
short-term floating rate notes, and/or issuing long-term debt.




Progress
Energy and its subsidiaries have approximately $11.505 billion in outstanding
long-term debt. Currently, approximately $860 million of the Utilities’ debt
obligations, approximately $620 million at PEC and approximately $240 million at
PEF, are tax-exempt auction rate securities insured by bond insurance. Bond
insurance generally allows companies to issue tax-exempt bonds with the
insurance company’s higher credit rating. Ambac Assurance Corporation insures
PEC’s bonds and Syncora Guarantee Inc., formerly XL Capital Assurance, Inc.,
insures PEF’s bonds.




The
tax-exempt bonds continue to experience failed auctions. In the event of a
failed auction, the bond holders cannot sell their bonds and the interest rate
is calculated based on a multiple of a market index such as the Securities
Industry and Financial Markets Association’s Municipal Swap Index or the London
Interbank Offered Rate (LIBOR). The interest rates for most of PEC’s portfolio
of tax-exempt securities reset based on the Securities




69




Industry
and Financial Markets Association’s Municipal Swap Index. The interest rates for
PEF’s portfolio of tax-exempt securities reset based on one-month LIBOR. The
multiple on our auction rate bonds is stable as long as the bonds are rated A3
or higher by Moody’s Investors Service, Inc. (Moody’s) or A- or higher by
Standard & Poor’s Rating Services (S&P). If the insurance company’s
rating falls below the Utilities’ ratings, then the bonds will be rated at
the Utilities’ senior secured debt rating, which is currently A2 by Moody’s and
A- by S&P for both Utilities. We do not expect any future rating actions on
Syncora Guarantee Inc. and Ambac Assurance Corporation to materially impact the
reset rates of the tax-exempt securities.




Assuming
the failed auctions persist, future interest rate resets on our tax-exempt
auction rate bond portfolio will be dependent on the volatility experienced in
the indices that dictate our interest rate resets and/or rating agency actions
that may move our tax-exempt bonds below A3/A-. We will continue to monitor this
market and evaluate options to mitigate our exposure to future
volatility.




The
performance of the capital markets affects the values of the assets held in
trust to satisfy future obligations under our defined benefit pension plans.
Although a number of factors impact our pension funding requirements, a decline
in the market value of these assets may significantly increase the future
funding requirements of the obligations under our defined benefit pension plans.
In 2009, contributions directly to pension plan assets are expected to
approximate $222 million for us, $164 million for PEC and $57 million for PEF.
An immaterial amount was contributed during the three months ended March 31,
2009 (See Note 10).




As
discussed in “Other Matters – Environmental Matters,” over the long term,
compliance with environmental regulations and meeting the anticipated load
growth at the Utilities as described under “Other Matters – Increasing Energy
Demand” will require the Utilities to make significant capital investments.
These anticipated capital investments are expected to be funded through a
combination of cash from operations and issuance of long-term debt, preferred
stock and common equity, which are dependent on our ability to successfully
access capital markets.  We may pursue joint ventures or similar
arrangements with third parties in order to share some of the financing and
operational risks associated with new baseload generation.  As discussed
under "Other Matters - Nuclear," PEF expects the schedule for its proposed
nuclear plant in Levy County, Florida (Levy) to shift by a minimum of
20 months from the 2016 to 2018 timeframe, which will reduce the near-term
capital expenditures for the project.




Certain
hedge agreements may result in the receipt of, or posting of, derivative
collateral with our counterparties, depending on the daily derivative position.
Fluctuations in commodity prices that lead to our return of collateral received
and/or our posting of collateral with our counterparties negatively impact our
liquidity. Substantially all derivative commodity instrument positions are
subject to retail regulatory treatment. After settlement of the derivatives and
the fuel is consumed, any realized gains or losses are passed through the fuel
cost-recovery clause. Due to the significant decline in natural gas prices since
December 31, 2008, we have posted additional collateral with counterparties. At
March 31, 2009, we had posted approximately $556 million of cash collateral
compared to $340 million of cash collateral posted at December 31, 2008. The
majority of our financial hedge agreements will settle in 2009 and 2010.
Additional commodity market price decreases could result in significant
increases in the derivative collateral that we are required to post with
counterparties. We continually monitor our derivative positions in relation to
market price activity.




The
amount and timing of future sales of securities will depend on market
conditions, operating cash flow and our specific needs. We may from time to time
sell securities beyond the amount immediately needed to meet capital
requirements in order to allow for the early redemption of long-term debt, the
redemption of preferred stock, the reduction of short-term debt or for other
corporate purposes.




REGULATORY
MATTERS AND RECOVERY OF COSTS




Regulatory
matters, including nuclear cost recovery, as discussed in Note 4 and “Other
Matters – Regulatory Environment,” and filings for recovery of environmental
costs, as discussed in Note 14 and in “Other Matters – Environmental Matters,”
may impact our future liquidity and financing activities. The impacts of these
matters, including the timing of recoveries from ratepayers, can be both a
source of and a use of future liquidity resources. Regulatory developments
expected to have a material impact on our liquidity are discussed
below.




As
discussed further in Note 4 and in “Other Matters – Regulatory Environment,” the
North Carolina, South Carolina and Florida legislatures passed energy
legislation that became law in recent years. These laws may impact




70




our
liquidity over the long term, including among others, provisions regarding cost
recovery, mandated renewable portfolio standards, demand-side management
(DSM) and energy efficiency.




PEC Cost-Recovery
Clause




On May 7,
2009, PEC filed with the Public Service Commission of South Carolina (SCPSC) for
a decrease in the fuel rate charged to its South Carolina ratepayers. PEC is
asking the SCPSC to approve a $13 million decrease in fuel rates driven by
declining fuel prices. If approved, the decrease would take effect July 1, 2009,
and would decrease
residential electric bills by $2.05 per 1,000 kWh, or 2.0 percent, for fuel cost
recovery. A hearing on the matter has been scheduled by the SCPSC for June 11,
2009. We cannot predict the outcome of this matter.




In 2008,
PEC filed an application with the SCPSC to establish procedures that encourage
investment in cost-effective energy-efficient technologies and energy
conservation programs and approve the establishment of an annual rider to allow
recovery for all costs associated with such programs, as well as the recovery of
appropriate incentives for investing in such programs. On January 23, 2009, PEC
filed a Stipulation Agreement between PEC and some of the other parties to the
proceeding. A hearing on this matter was held on February 12, 2009. We cannot
predict the outcome of this matter.  On
May 6, 2009, the SCPSC approved the Stipulation
Agreement.




PEF Base
Rates




As a
result of a base rate proceeding in 2005, PEF is party to a base rate settlement
agreement that was effective with the first billing cycle of January 2006 and
will remain in effect through the last billing cycle of December
2009.




On March
20, 2009, in anticipation of the expiration of its current base rate settlement
agreement, PEF filed with the Florida Public Service Commission (FPSC) a
proposal for an increase in base rates effective January 1, 2010. In its filing,
PEF requested the FPSC to approve calendar year 2010 as the projected test
period for setting new base rates and approve annual rate relief for PEF of $499
million, which includes PEF’s petition for a combined $76 million of new base
rates in 2009 as discussed below. The request for increased base rates is based,
in part, on investments PEF is making in its generating fleet and in its
transmission and distribution systems. If approved by the FPSC, this portion of
the new base rates would increase residential bills by approximately $9.07 per
1,000 kWh, or 7.1 percent, effective January 1, 2010. A ruling by the FPSC is
expected in November 2009. We cannot predict the outcome of this
matter.




Included
within the base rate proposal is a request for an interim rate increase of $13
million. Additionally, on March 20, 2009, PEF petitioned the FPSC for a limited
proceeding to include in base rates revenue requirements of $63 million for the
repowered Bartow power plant, which is expected to begin commercial operation in
June 2009. If approved by the FPSC, PEF’s petitions for a combined $76 million
of new base rates would increase residential bills by approximately $4.76 per
1,000 kWh, or 3.9 percent, effective July 1, 2009.  On May 7, 2009, the
staff of the FPSC recommended that PEF be allowed to increase its base rates,
subject to refund, by a total of $70 million, effective the first
billing cycle 30 days following the commercial operation in-sevice date of
the repowered Bartow power plant.  However, a ruling by the FPSC
is expected later in May 2009. We cannot predict the outcome of this
matter.




PEF Cost-Recovery
Clause




On April
6, 2009, PEF received approval from the FPSC to reduce its 2009 fuel
cost-recovery factors by an amount sufficient to achieve a $206 million
reduction in fuel charges to retail customers as a result of effective fuel
purchasing strategies and lower fuel prices. The approval reduces residential
customers’ fuel charges by $6.90 per 1,000 kWh, or 5.0 percent, starting with
the first April 2009 billing cycle. Commercial and industrial customers will see
similar reductions.




On
October 10, 2007, the FPSC issued an order requiring PEF to refund its
ratepayers $14 million, including interest, over a 12-month period beginning
January 1, 2008. The refund was returned to the ratepayers through a reduction
of prior year under-recovered fuel costs. The FPSC also ordered PEF to address
whether it was prudent in its 2006 and 2007 coal purchases for CR4 and CR5. On
February 2, 2009, Florida’s Office of Public Counsel (OPC) filed direct
testimony in this hearing alleging that during 2006 and 2007, PEF collected
excessive fuel costs and sulfur dioxide (SO2) allowance
costs of $61 million before interest. The OPC claimed that these excessive costs
were attributed to PEF’s ongoing practice of not blending the most economical
sources of coal at its CR4 and CR5 plants. A hearing on PEF’s 2006 and 2007 coal
purchases was held April 13-15, 2009.  During the hearing, the OPC




71




reduced
the alleged excessive fuel costs to $33 million before interest. We expect a
decision by the FPSC in June 2009. PEF believes its coal procurement practices
have been prudent. We cannot predict the outcome of this matter.




PEF has
received approval from the FPSC for recovery through the ECRC of the majority of
costs associated with the remediation of distribution and substation
transformers, which were estimated to be $19 million at March 31, 2009. The FPSC
has approved cost recovery of PEF’s prudently incurred costs necessary to
achieve its integrated strategy
to address compliance with the Clean Air Interstate Rule (CAIR), the Clean Air
Mercury Rule (CAMR) and the Clean Air Visibility Rule (CAVR) through the ECRC
(See “Other Matters – Environmental Matters” for discussion regarding the CAIR,
CAMR and CAVR).




Nuclear Cost
Recovery




PEF is
allowed to recover prudently incurred site selection costs, preconstruction
costs and the carrying cost on construction cost balances on an annual basis
through the capacity cost-recovery clause. Such amounts will not be included in
PEF’s rate base when the plant is placed in commercial operation. The nuclear
cost-recovery rule also has a provision to recover costs should the project be
abandoned after the utility receives a final order granting a Determination of
Need. These costs include any unrecovered construction work in progress at the
time of abandonment and any other prudent and reasonable exit costs. In
addition, the rule requires the FPSC to conduct an annual prudence review of the
reasonableness and prudence of all such costs, including construction costs, and
such determination shall not be subject to later review except upon a finding of
fraud, intentional misrepresentation or the intentional withholding of key
information by the utility. On April 6, 2009, PEF received approval from the
FPSC to defer until 2010 the recovery of $198 million of nuclear preconstruction
costs for PEF’s proposed nuclear plant in Levy, which the FPSC had authorized to
be collected in 2009. The approval reduces residential customers’ nuclear
cost-recovery charge by $7.80 per 1,000 kWh, or 5.7 percent, starting with the
first April 2009 billing cycle. Commercial and industrial customers will see
similar reductions.




On May 1,
2009, pursuant to the FPSC nuclear cost-recovery rule, PEF filed a petition to
recover $446 million of pre-construction and carrying costs incurred or
anticipated to be incurred during 2009 as well as the projected 2010 costs
associated with the Levy and CR3 uprate projects. In an effort to help mitigate
the initial price impact on its customers, as part of its filing, PEF has
proposed collecting certain costs over a five-year period, with associated
carrying costs. The deferral would result in a nuclear cost-recovery charge of
$6.69 per 1,000 kWh for residential customers, which is approximately half of
the amount PEF is eligible to recover in 2010 under the nuclear cost-recovery
rule. If approved, the charges would begin with the first January 2010 billing
cycle. The FPSC has scheduled hearings in this matter for September 8-11, 2009,
with a decision expected in October 2009. We cannot predict the outcome of this
matter.




OFF-BALANCE SHEET
ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS




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




GUARANTEES




At March
31, 2009, our guarantees have not changed materially from what was reported in
the 2008 Form 10-K.




MARKET
RISK AND DERIVATIVES




Under our
risk management policy, we may use a variety of instruments, including swaps,
options and forward contracts, to manage exposure to fluctuations in commodity
prices and interest rates. See Note 11 and Item 3, “Quantitative and Qualitative
Disclosures About Market Risk,” for a discussion of market risk and
derivatives.




72






CONTRACTUAL
OBLIGATIONS




As part
of our ordinary course of business, we and the Utilities enter into various
long- and short-term contracts for fuel requirements at our generating plants.
Significant changes from the commitment amounts reported in Note 22A in the 2008
Form 10-K can result from new contracts, changes in existing contracts along
with the impact of fluctuations in current estimates of future market prices for
those contracts that are market price indexed. In most cases, these contracts
contain provisions for price adjustments, minimum purchase levels, and other
financial commitments.   Additional commitments for fuel and related
transportation will be required to supply the Utilities' future needs.  At
March 31, 2009, our and the Utilities contractual cash obligations and other
commercial commitments have not changed materially from what was reported in the
2008 Form 10-K however, PEF now expects to shift the schedule for its planned
Levy nuclear project.  Although the overall schedule impact is not certain
at this time, PEF expects the schedule to shift from the 2016 to 2018 timeframe
by a minimum of 20 months.  We anticipate amending the Levy Engineering,
Procurement and Construction ("EPC") agreement due to the schedule shift but
cannot predict the impact such amendment might have on the project's cost,
if any.  Refer to "Other Matters - Nuclear" below for further discussion of
the Levy nuclear project.




OTHER
MATTERS




SYNTHETIC
FUELS TAX CREDITS




Historically,
we had substantial operations associated with the production of coal-based solid
synthetic fuels as defined under Section 29 of the Internal Revenue Code (the
Code) (Section 29) and as redesignated effective 2006 as Section 45K of the Code
as discussed below. The production and sale of these products qualified for
federal income tax credits so long as certain requirements were satisfied.
Qualifying synthetic fuels facilities entitled their owners to federal income
tax credits based on the barrel of oil equivalent of the synthetic fuels
produced and sold by these plants. The synthetic fuels tax credit program
expired at the end of 2007 and the synthetic fuels businesses were abandoned and
reclassified to discontinued operations.




Legislation
enacted in 2005 redesignated the Section 29 tax credit as a general business
credit under Section 45K of the Code effective January 1, 2006. The previous
amount of Section 29 tax credits that we were allowed to claim in any calendar
year through December 31, 2005, was limited by the amount of our regular federal
income tax liability. Section 29 tax credit amounts allowed but not utilized are
carried forward indefinitely as deferred alternative minimum tax credits. The
redesignation of Section 29 tax credits as a Section 45K general business credit
removed the regular federal income tax liability limit on synthetic fuels
production and subjects the credits to a one-year carry back period and a
20-year carry forward period.




Total
Section 29/45K credits generated under the synthetic fuels tax credit program
(including those generated by Florida Progress prior to our acquisition), were
$1.891 billion, of which $1.044 billion has been used through March 31, 2009, to
offset regular federal income tax liability and $847 million is being carried
forward as deferred tax credits.




See Note
15C for additional discussion related to our previous synthetic fuels
operations.




REGULATORY
ENVIRONMENT




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




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




The
American Recovery and Reinvestment Act signed into law in February 2009 contains
provisions promoting energy efficiency and renewable energy, including $11
billion for Smart Grid-related technologies, $6.3 billion for energy-efficiency
and conservation grants and $2 billion in tax credits for the purchase of
plug-in electric vehicles.




73




Also, the
Obama administration has announced a goal of sparking a new energy revolution by
stimulating transmission and promoting renewable resources while also pricing
greenhouse gas emissions and setting a federal requirement for renewable energy.
We are currently reviewing the impact the new legislation might have on our
operations. The impact of the new legislation and regulation resulting from
other federal initiatives cannot be determined at this time.




Current
retail rate matters affected by state regulatory authorities are discussed in
Notes 4A and 4B. This discussion identifies specific retail rate matters, the
status of the issues and the associated effects on our consolidated financial
statements.




Florida
energy law enacted in 2008 includes provisions that would, among other things,
(1) help enhance the ability to cost-effectively site transmission lines; (2)
require the FPSC to develop a renewable portfolio standard that the FPSC would
present to the legislature for ratification in 2009; (3) direct the Florida
Department of Environmental Protection (FDEP) to develop rules establishing a
cap-and-trade program to regulate greenhouse gas emissions that the FDEP would
present to the legislature no earlier than January 2010 for ratification by the
legislature; and (4) establish a new Florida Energy and Climate Commission as
the principal governmental body to develop energy and climate
policy for the state and to make recommendations to the governor and legislature
on energy and climate issues. In complying with the provisions of the law, PEF
would be able to recover its reasonable prudent compliance costs. However, until
the rulemaking processes are completed, we cannot predict the costs of complying
with the law.




On July
13, 2007, the governor of Florida issued executive orders to address reduction
of greenhouse gas emissions. The executive orders call for the first
southeastern state cap-and-trade program and include adoption of a maximum
allowable emissions level of greenhouse gases for Florida utilities. The
standard will require, at a minimum, the following three reduction milestones:
by 2017, emissions not greater than Year 2000 utility sector emissions; by 2025,
emissions not greater than Year 1990 utility sector emissions; and by 2050,
emissions not greater than 20 percent of Year 1990 utility sector emissions. The
FDEP’s first workshop on the greenhouse gas cap-and-trade rulemaking was held
December 11, 2008. The rulemaking is expected to continue through 2009, and the
rule requires legislative ratification before implementation.




The
executive orders also requested that the FPSC initiate a rulemaking by September
1, 2007, that would (1) require Florida utilities to produce at least 20 percent
of their electricity from renewable sources; (2) reduce the cost of connecting
solar and other renewable energy technologies to Florida’s power grid by
adopting uniform statewide interconnection standards for all utilities; and (3)
authorize a uniform, statewide method to enable residential and commercial
customers, who generate electricity from on-site renewable technologies of up to
1 megawatt (MW) in capacity, to offset their consumption over a billing period
by allowing their electric meters to turn backward when they generate
electricity (net metering). On January 12, 2009, the FPSC approved a draft
Florida renewable portfolio standard (Florida RPS) rule with a goal of 20
percent renewable energy production by 2020. The FPSC provided the draft Florida
RPS rule to the Florida legislature in February 2009. The legislature will
review, ratify as is, make revisions, or decide not to have a Florida RPS rule
at all. We cannot predict the outcome of this matter.




We cannot
predict the costs of complying with the laws and regulations that may ultimately
result from these executive orders. Our balanced solution, as described in
“Increasing Energy Demand,” includes greater investment in energy efficiency,
renewable energy and state-of-the-art generation and demonstrates our commitment
to environmental responsibility.




North
Carolina energy law enacted in 2007 includes provisions for a North Carolina
Renewable Energy and Energy Efficiency Portfolio Standard (NC REPS), expansion
of the definition of the traditional fuel clause and recovery of the costs of
new DSM and energy-efficiency programs through an annual DSM clause. On
February 29, 2008, the NCUC issued an order adopting final rules for
implementing North Carolina’s 2007 energy law. The rules include filing
requirements regarding NC REPS compliance and inclusion in the Utility’s
integrated resource plan. The order also establishes a schedule and filing
requirements for DSM and energy-efficiency cost recovery and financial
incentives. Rates for the DSM and energy-efficiency clause and the NC REPS
clause will be set based on projected costs with true-up provisions. In 2008,
PEC filed for NCUC approval of multiple DSM and energy-efficiency programs. The
majority of the programs has been approved by the NCUC or is pending further
review. We cannot predict the outcome of the DSM and energy-efficiency filings
pending further approval by the NCUC or whether the programs will produce the
expected operational and economic results.




74




LEGAL




We are
subject to federal, state and local legislation and court orders. The specific
issues, the status of the issues, accruals associated with issue resolutions and
our associated exposures are discussed in detail in Note 15C.




INCREASING
ENERGY DEMAND




Meeting
the anticipated long-term growth within the Utilities’ service territories will
require a balanced approach. The three main elements of this balanced solution
are: (1) expanding our energy-efficiency programs; (2) investing in the
development of alternative energy resources for the future; and (3) operating
state-of-the-art plants that produce energy cleanly and efficiently by
modernizing existing plants and pursuing options for building new plants and
associated transmission facilities.




We are
actively pursuing expansion of our DSM, energy-efficiency and conservation
programs as energy efficiency is one of the most effective ways to reduce energy
costs, offset the need for new power plants and protect the environment. DSM
programs include, but are not limited to, any program or initiative that shifts
the timing of electricity use from peak to nonpeak periods and includes load
management, electricity system and operating controls, direct load control,
interruptible load, and electric system equipment and operating controls. Our
energy-efficiency program provides simple, low-cost options for residential
customers to reduce energy use, promotes home energy checks, provides tools and
programs for large and small businesses to minimize their energy use and
provides an interactive Internet Web site with online calculators, programs and
efficiency tips.




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




In the
coming years, we will continue to invest in existing plants and consider plans
for building new generating plants. Due to the anticipated long-term growth in
our service territories, we estimate that we will require new generation
facilities in both Florida and the Carolinas toward the end of the next decade,
and we are evaluating the best available options for this generation, including
advanced design nuclear and gas technologies. At this time, no definitive
decisions have been made to construct new nuclear plants. In 2007, PEC announced
a two-year moratorium on constructing new coal-fired plants while pursuing
expansion of energy-efficiency and conservation programs. If PEC proceeds with
construction of a new nuclear plant, the new plant would not be online until at
least 2019 (See “Nuclear” below).




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




In 2008,
Congress authorized $38.5 billion in loan guarantee authority for innovative
energy projects. Of the total provided, $18.5 billion is set aside for nuclear
power facilities, $2 billion for advanced nuclear facilities for the "front-end"
of the nuclear fuel cycle, $10 billion for renewable and/or energy-efficient
systems and manufacturing and distributed energy generation/transmission and
distribution, $6 billion for coal-based power generation and industrial
gasification at retrofitted and new facilities that incorporate carbon capture
and sequestration or other beneficial uses of carbon, and $2 billion for
advanced coal gasification. In June 2008, the DOE announced solicitations for a
total of up to $30.5 billion of the amount authorized by Congress in federal
loan guarantees for projects that employ advanced energy technologies that
avoid, reduce or sequester air pollutants or greenhouse gas emissions and
advanced nuclear facilities for the “front-end” of the nuclear fuel
cycle.




PEF
submitted Part I of the Application for Federal Loan Guarantees for Nuclear
Power Facilities on September 29, 2008, for Levy. PEF was one of 19 applicants
that submitted Part I of the application. The program requires that the
guarantee be in a first lien position on all assets of the project, which
conflicts with PEF’s current mortgage. Obtaining the required approval to amend
the current mortgage from 100 percent of PEF’s current bondholders would be
unlikely, and current secured debt of $4.0 billion would need to be refinanced
with unsecured debt to meet the requirements of the guarantee. In addition, the
costs associated with obtaining the loan guarantee are unclear. PEF decided not
to pursue the loan guarantee program and did not submit Part II of the
application, which was due




75




on
December 19, 2008. However, this decision does not preclude PEF from revisiting
the program at a later date if there are changes to the program. We cannot
predict if PEF will pursue this program further.




A new
nuclear plant may be eligible for the federal production tax credits and risk
insurance provided by EPACT. EPACT provides an annual tax credit of 1.8 cents
per kWh for nuclear facilities for the first eight years of operation. The
credit is limited to the first 6,000 MW of new nuclear generation in the United
States and has an annual cap of $125 million per 1,000 MW of national MW
capacity limitation allocated to the unit. In April 2006, the IRS provided
interim guidance that the 6,000 MW of production tax credits generally will be
allocated to new nuclear facilities that filed license applications with the NRC
by December 31, 2008, had poured safety-related concrete prior to
January 1, 2014, and were placed in service before January 1, 2021. There is no
guarantee that the interim guidance will be incorporated into the final
regulations governing the allocation of production tax credits. Multiple
utilities have announced plans to pursue new nuclear plants. There is no
guarantee that any nuclear plant we construct would qualify for these or other
incentives. We cannot predict the outcome of this matter.




NUCLEAR




Nuclear
generating units are regulated by the NRC. In the event of noncompliance, the
NRC has the authority to impose fines, set license conditions, shut down a
nuclear unit or take some combination of these actions, depending upon its
assessment of the severity of the situation, until compliance is achieved. Our
nuclear units are periodically removed from service to accommodate normal
refueling and maintenance outages, repairs, uprates and certain other
modifications.




The NRC
operating licenses for PEC’s nuclear units expire between 2030 and 2046. The NRC
operating license held by PEF for Crystal River Unit No. 3 (CR3) currently
expires in December 2016. On March 9, 2009, the NRC docketed, or accepted for
review, PEF’s application for a 20-year extension on the operating license for
CR3, which would extend the operating license through 2036, if approved.
Docketing the application does not preclude additional requests for information
as the review proceeds; nor does it indicate whether the NRC will renew the
license. The license renewal application for CR3 is currently under review by
the NRC with a decision expected in 2010 or 2011.




POTENTIAL
NEW CONSTRUCTION




While we
have not made a final determination on nuclear construction, we have taken steps
to keep open the option of building a plant or plants. During 2008, PEC and PEF
filed combined license (COL) applications to potentially construct new nuclear
plants in North Carolina and Florida. The NRC estimates that it will take
approximately three to four years to review and process the COL
applications.




On
January 23, 2006, we announced that PEC selected a site at the Shearon Harris
Nuclear Plant (Harris) to evaluate for possible future nuclear expansion. We
selected the Westinghouse Electric AP1000 reactor design as the technology upon
which to base PEC’s application submission. On February 19, 2008, PEC filed its
COL application with the NRC for two additional reactors at Harris. On April 17,
2008, the NRC docketed, or accepted for review, the Harris application.
Docketing the application does not preclude additional requests for information
as the review proceeds; nor does it indicate whether the NRC will issue the
license. One petition to intervene in the licensing proceeding was filed with
the NRC within the 60-day notice period. We cannot predict the outcome of this
matter. If we receive approval from the NRC and applicable state agencies, and
if the decisions to build are made, a new plant would not be online until at
least 2019 (See “Increasing Energy Demand” above).




On
December 12, 2006, we announced that PEF selected a greenfield site at Levy to
evaluate for possible future nuclear expansion. We selected the Westinghouse
Electric AP1000 reactor design as the technology upon which to base PEF’s
application submission. In 2007, PEF completed the purchase of approximately
5,000 acres for Levy and associated transmission needs. In 2007, both the Levy
County Planning Commission and the Board of Commissioners voted unanimously in
favor of PEF’s requests to change the comprehensive land use plan. On May 29,
2008, the Florida Department of Community Affairs (FDCA) issued its final
determination that the amendments to the Levy County Comprehensive Plan are in
compliance with land use regulations.




In 2008,
PEF submitted filings for two key state approvals. First, on March 11, 2008, PEF
filed a Petition for a Determination of Need for Levy with the FPSC. The FPSC
issued a final order granting PEF’s petition for Levy on August 12, 2008.
Second, on June 2, 2008, PEF filed its application for Site Certification with
the FDEP. On




76




January
12, 2009, the FDEP filed a favorable staff analysis report in advance of site
certification hearings. On March 12, 2009, the technical proceedings concluded,
and an order from the administrative law judge is expected by the end of May
2009.




On July
30, 2008, PEF filed its COL application with the NRC for two reactors. PEF also
completed and submitted a Limited Work Authorization request for Levy concurrent
with the COL application. On October 6, 2008, the NRC docketed, or accepted for
review, the Levy application. Docketing the application does not preclude
additional requests for information as the review proceeds; nor does it indicate
whether the NRC will issue the license. On February 24, 2009, PEF received the
NRC’s schedule for review and approval of the COL. One petition to intervene in the
licensing proceeding was filed with the NRC within the 60-day notice period. On
April 20-21, 2009, the Atomic Safety and Licensing Board heard oral arguments on
whether any of the intervener’s proposed contentions will be admitted in the
Levy COL proceeding. We cannot predict the outcome of this matter.




Based on
the NRC’s treatment of certain work prior to the issuance of the Levy COL, PEF
now expects a schedule shift for the commercial operation dates of the Levy
nuclear units. Specifically, PEF’s initial schedule anticipated the ability to
perform certain site work pursuant to a Limited Work Authorization from the NRC
prior to COL receipt. The NRC Staff has recently determined, however, that
certain schedule-critical work that PEF had proposed to perform within the
Limited Work Authorization scope will not be authorized until the NRC issues the
COL. Consequently, excavation and foundation preparation work will be shifted
until after COL issuance. Although the overall schedule impact is not certain at
this time, PEF expects the schedule to shift from the 2016 to 2018 timeframe by
a minimum of 20 months. We anticipate amending the EPC agreement discussed below
due to the schedule shift but cannot predict the impact such amendment might
have on the project’s cost, if any.




As
discussed below, the schedule shift will reduce the near-term capital
expenditures for the project and also reduce the near-term impact on customer
rates. The schedule shift will also allow more time for certainty around federal
climate change policy, which is currently being debated, and could result in
more favorable financing than currently available. We believe that continuing,
although at a slower pace than initially anticipated, is a reasonable and
prudent course at this early stage of the project. We still consider Levy as
PEF’s preferred baseload generation option, taking into account cost, potential
carbon regulation, fossil fuel price volatility and the benefits of fuel
diversification. Along with the FPSC’s annual prudence reviews, we will continue
to evaluate the project on an ongoing basis based on certain criteria, including
public, regulatory and political support; adequate financial cost-recovery
mechanisms; and availability and terms of capital financing.




PEF
signed the EPC agreement on December 31, 2008, with Westinghouse Electric
Company LLC and Stone & Webster, Inc. for two Westinghouse AP1000 nuclear
units to be constructed at Levy. More than half of the approximate $7.650
billion contract price is fixed or firm with agreed upon escalation factors. The
total cost for the two generating units is estimated to be approximately $14
billion. This total cost estimate includes land, plant components, financing
costs, construction, labor, regulatory fees and the initial core for the two
units. An additional $3 billion is estimated for the necessary transmission
equipment and approximately 200 miles of transmission lines associated with the
project. As noted above, the final cost of the project will depend on the
completion dates, which will be determined in large part by the NRC review
schedule. The EPC agreement includes various incentives, warranties, performance
guarantees, liquidated damage provisions and parent guarantees designed to
incent the contractor to perform efficiently. For termination without cause, the
EPC agreement contains exit provisions with termination fees, which may be
significant, that vary based on the termination circumstances.




Florida
regulations allow investor-owned utilities such as PEF to recover prudently
incurred site selection costs, preconstruction costs and the carrying cost on
construction cost balance of a nuclear power plant prior to commercial
operation. The costs are recovered on an annual basis through the capacity
cost-recovery clause. Such amounts will not be included in a utility’s rate base
when the plant is placed in commercial operation. The nuclear cost-recovery rule
also has a provision to recover costs should the project be abandoned after the
utility receives a final order granting a Determination of Need. These costs
include any unrecovered construction work in progress at the time of abandonment
and any other prudent and reasonable exit costs. In addition, the rule 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.




In 2008,
PEF sought and received approval from the FPSC to recover Levy preconstruction
and carrying charges of $357 million as well as site selection costs of $38
million through the 2009 capacity cost-recovery clause. In 2009,




77




PEF
received approval to defer until 2010 the recovery of $198 million of these
costs (See Note 4B). PEF will be a participant in the annual nuclear
cost-recovery proceeding, which was opened by the FPSC on January 5, 2009. The
proceeding will occur throughout the year with an order expected by the end of
2009. On May 1, 2009, pursuant to the FPSC nuclear cost-recovery rule, PEF filed
a petition to recover $446 million of pre-construction and carrying costs
incurred or anticipated to be incurred during 2009 as well as the projected 2010
costs associated with the Levy and CR3 uprate projects. In an effort to help
mitigate the initial price impact on its customers, as part of its filing, PEF
has proposed collecting certain costs over a five-year period, with associated
carrying costs. The deferral would result in a nuclear cost-recovery charge of
$6.69 per 1,000 kWh for residential customers, which is approximately half of
the amount PEF is eligible to recover in 2010 under the nuclear cost-recovery
rule. If approved, the charges would begin with the first January 2010 billing
cycle. The FPSC has scheduled hearings in this matter for September 8-11, 2009,
with a decision expected in October 2009. We cannot predict the outcome of this
matter.




PEC’s
jurisdictions also have laws encouraging nuclear baseload generation. South
Carolina law includes provisions for cost-recovery mechanisms associated with
nuclear baseload generation. North Carolina law authorizes the NCUC to allow
annual prudence reviews of baseload generating plant construction costs and
removes the requirement that a public utility prove financial distress before it
may include construction work in progress in rate base and adjust rates,
accordingly, in a general rate case while a baseload generating plant is under
construction (See “Other Matters – Regulatory Environment”).




SPENT
NUCLEAR FUEL MATTERS




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 (D.C. Court of Appeals) for review of the Congressional override
resolution. These same parties also challenged the EPA’s radiation standards for
Yucca Mountain. On July 9, 2004, the Court rejected the challenge to the
constitutionality of the resolution approving Yucca Mountain, but ruled that the
EPA was wrong to set a 10,000-year compliance period in the radiation protection
standard. On September 30, 2008, the EPA issued final rules for limiting
radiation exposure at Yucca Mountain. The EPA retained the dose limit of 15
millirem per year for the first 10,000 years and established a dose limit of 100
millirem for annual exposure per year between 10,000 years and 1 million years.
In February 2009, the NRC approved a final rule for the waste repository at
Yucca Mountain incorporating these radiation protection standards. On October
10, 2008, the state of Nevada again filed suit with the D.C. Court of Appeals
challenging the EPA standard.




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




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




On August
5, 2008, the DOE announced that its estimated cost to build and commence
operations at the Yucca Mountain facility has increased from $57.5 billion to
$96.2 billion due to an increase in material costs, an increase in the quantity
of spent fuel to store and a refinement of the repository’s design. The 2010
federal budget proposed by the Obama administration largely eliminates funding
for the Yucca Mountain facility while the administration devises a new strategy
toward nuclear waste disposal. We cannot predict the outcome of this
matter




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




78




With
certain modifications and additional approvals by the NRC, including the
installation of on-site dry cask storage facilities at PEC’s Robinson Nuclear
Plant, Brunswick Nuclear Plant and CR3, the Utilities’ spent nuclear fuel
storage facilities will be sufficient to provide storage space for spent fuel
generated by their respective systems through the expiration of the operating
licenses, including any license extensions, for their nuclear generating units.
Harris has sufficient storage capacity in its spent fuel pools through the
expiration of its extended operating license.




See Note
15C for information about the complaint filed by the Utilities in the United
States Court of Federal Claims against the DOE for its failure to fulfill its
contractual obligation to receive spent fuel from nuclear plants. Failure to
open the Yucca Mountain or other facility would leave the DOE open to further
claims by utilities.




ENVIRONMENTAL
MATTERS




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




HAZARDOUS
AND SOLID WASTE MANAGEMENT




The
provisions of the Comprehensive Environmental Response, Compensation and
Liability Act of 1980, as amended (CERCLA), authorize the EPA to require the
cleanup of hazardous waste sites. This statute imposes retroactive joint and
several liabilities. Some states, including North Carolina, South Carolina and
Florida, have similar types of statutes. We are periodically notified by
regulators, including the EPA and various state agencies, of our involvement or
potential involvement in sites that may require investigation and/or
remediation. There are presently several sites with respect to which we have
been notified of our potential liability by the EPA, the state of North
Carolina, the state of Florida or potentially responsible parties (PRP) groups.
Various organic materials associated with the production of manufactured gas,
generally referred to as coal tar, are regulated under federal and state laws.
PEC and PEF are each PRPs at several manufactured gas plant (MGP) sites. We are
also currently in the process of assessing potential costs and exposures at
other sites. These costs are eligible for regulatory recovery through either
base rates or cost-recovery clauses (See Notes 4 and 13). Both PEC and PEF
evaluate potential claims against other PRPs and insurance carriers and plan to
submit claims for cost recovery where appropriate. The outcome of potential and
pending claims cannot be predicted. Hazardous and solid waste management matters
are discussed in detail in Note 14A.




The EPA
and a number of states are considering additional regulatory measures that may
affect management, treatment, marketing and disposal of coal combustion
products, primarily ash, from each of the Utilities’ coal-fired plants. Revised
or new laws or regulations under consideration may impose changes in solid waste
classifications or groundwater protection environmental controls. We are
evaluating the effect on groundwater quality from past and current operations,
which may result in operational changes and additional measures. These issues
are also under evaluation by state agencies. Compliance plans and estimated
costs to meet the requirements of new regulations will be determined when those
new regulations are finalized.




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




AIR
QUALITY AND WATER QUALITY




We are,
or may ultimately be, subject to various current and proposed federal, state and
local environmental compliance laws and regulations, which likely would result
in increased capital expenditures and O&M expenses. Additionally, Congress
is considering legislation that would require reductions in air emissions of
NOx, SO2, CO2 and
mercury. Some of these proposals establish nationwide caps and emission rates
over an extended period of time. This national multipollutant approach to air
pollution control could involve significant capital costs that could be material
to our financial position or results of operations. Control equipment installed
pursuant to the provisions of CAIR, CAVR and mercury regulation, which are
discussed below, may address some of the issues outlined above.




79




PEC and
PEF have been developing an integrated compliance strategy to meet the
requirements of the CAIR, CAVR and mercury regulation (see discussion of the
court decisions that impacted the CAIR, the delisting determination and the CAMR
below). The CAVR requires the installation of best available retrofit technology
(BART) on certain units. However, the outcome of these matters cannot be
predicted.




Clean Smokestacks
Act




In June
2002, the Clean Smokestacks Act was enacted in North Carolina requiring the
state's electric utilities to reduce the emissions of NOx and SO2 from their
North Carolina coal-fired power plants in phases by 2013. PEC currently has
approximately 5,000 MW of coal-fired generation capacity in North Carolina that
is affected by the Clean Smokestacks Act. On March 31, 2009, PEC filed its
annual estimate with the NCUC of the total capital expenditures to meet emission
targets under the Clean Smokestacks Act by the end of 2013, which were
approximately $1.4 billion at the time of the filing. We are continuing to
evaluate various design, technology and new generation options that could change
expenditures required by the Clean Smokestacks Act. Changes in projected fuel
sources may require us to incur costs, which are not currently estimable, to
install additional controls subsequent to 2013 in order to remain compliant with
the requirements of the Clean Smokestacks Act. O&M expenses increase with
the operation of pollution control equipment due to the cost of commodities such
as ammonia and limestone used in emissions control technologies (reagents),
additional personnel and general maintenance associated with the pollution
control equipment. Legislation in North Carolina and South Carolina expanded the
traditional fuel clause to include the annual recovery of reagents and certain
other costs; all other O&M expenses are currently recoverable through base
rates.




Two of
PEC’s largest coal-fired generating units (the Roxboro No. 4 and Mayo Units)
impacted by the Clean Smokestacks Act are jointly owned. In 2005, PEC entered
into an agreement with the joint owner to limit their aggregate costs associated
with capital expenditures to comply with the Clean Smokestacks Act and
recognized a liability related to this indemnification (See Note
14B).




Clean Air Interstate
Rule




The CAIR
issued by the EPA on March 10, 2005, required the District of Columbia and 28
states, including North Carolina, South Carolina and Florida, to reduce NOx and
SO2
emissions. The CAIR set emission limits to be met in two phases beginning in
2009 and 2015, respectively, for NOx and beginning in 2010 and 2015,
respectively, for SO2. States
were required to adopt rules implementing the CAIR and the EPA approved the
North Carolina CAIR, the South Carolina CAIR and the Florida CAIR in
2007.




PEF
participated in a coalition of Florida utilities that filed a challenge to the
CAIR as it applied to Florida (PEF withdrew from the coalition during the fourth
quarter of 2008). On July 11, 2008, the D.C. Court of Appeals issued its
decision on multiple challenges to the CAIR, including the Florida challenge,
which vacated the CAIR in its entirety. On December 23, 2008, the D.C. Court of
Appeals remanded the CAIR, without vacating the rule, for the EPA to conduct
further proceedings consistent with the D.C. Court of Appeals’ prior opinion.
This decision leaves the CAIR in effect until such time that it is revised or
replaced. The EPA informed the D.C. Court of Appeals that development and
finalization of a replacement rule could take approximately two years. The
outcome of this matter cannot be predicted.




PEF is
continuing construction of its in-process emission control projects. On December
18, 2008, PEF and the FDEP announced an agreement under which PEF will retire
CR1 and CR2 as coal-fired units and complete construction of its emission
control projects at CR4 and CR5. CR1 and CR2 will be retired after the second
proposed nuclear unit at Levy completes its first fuel cycle, which was
anticipated to be around 2020. As discussed under “Other Matters – Nuclear,” PEF
expects the Levy schedule to shift by a minimum of 20 months from the 2016 to
2018 timeframe. PEF is required to advise the FDEP of any developements that
will delay the retirement of CR1 and CR2 beyond the orginally anticipated
completion date of the first fuel cycle for Levy Unit 2.  Accordingly, PEF
has advised the FDEP of the Levy schedule shift.  We are currently
evaluating the impacts of the Levy schedule shift. We cannot predict the outcome
of this matter.




80




Clean Air Mercury
Rule




On March
15, 2005, the EPA finalized two separate but related rules: the CAMR that set
mercury emissions limits to be met in two phases beginning in 2010 and 2018,
respectively, and encouraged a cap-and-trade approach to achieving those caps,
and a delisting rule that eliminated any requirement to pursue a maximum
achievable control technology approach for limiting mercury emissions from
coal-fired power plants. On February 8, 2008, the D.C. Court of Appeals vacated
the delisting determination and the CAMR. The U.S. Supreme Court declined to
hear an appeal of the D.C. Court of Appeals decision in January 2009. As a
result, the EPA subsequently announced that it will develop a maximum achievable
control technology (MACT) standard consistent with the agency’s original listing
determination. The three states in which the Utilities operate adopted mercury
regulations implementing the CAMR and submitted their state implementation rules
to the EPA. The North Carolina mercury rule contains a requirement
that all coal-fired units in the state install mercury controls by December 31,
2017, and requires compliance plan applications to be submitted in 2013. The
outcome of this matter cannot be predicted.




Clean Air Visibility
Rule




On June
15, 2005, the EPA issued the final CAVR. The EPA’s rule requires states to
identify facilities, including power plants, built between August 1962 and
August 1977 with the potential to produce emissions that affect visibility in
156 specially protected areas, including national parks and wilderness areas,
designated as Class I areas. To help restore visibility in those areas, states
must require the identified facilities to install BART to control their
emissions. PEC’s BART-eligible units are Asheville Units No. 1 and No. 2,
Roxboro Units No. 1, No. 2 and No. 3, and Sutton Unit No. 3. PEF’s BART-eligible
units are Anclote Units No. 1 and No. 2, Bartow Unit No. 3 and CR1 and CR2. The
reductions associated with BART begin in 2013. As discussed above, on December
18, 2008, PEF and the FDEP announced an agreement under which PEF will retire
CR1 and CR2 as coal-fired units.




The CAVR
included the EPA’s determination that compliance with the NOx and SO2
requirements of the CAIR could be used by states as a BART substitute to fulfill
BART obligations, but the states could require the installation of additional
air quality controls if they did not achieve reasonable progress in improving
visibility. The D.C. Court of Appeals’ December 23, 2008 decision remanding the
CAIR maintained its implementation such that CAIR satisfies BART for SO2 and NOx.
Should this determination change as the CAIR is revised, CAVR compliance
eventually may require consideration of NOx and SO2 emissions
in addition to particulate matter emissions for BART-eligible units. We
are assessing the potential impact of BART and its implications with
respect to our plans and estimated costs to comply with the
CAVR. On December 4, 2007, the FDEP finalized a Regional Haze
implementation rule that goes beyond BART by requiring sources significantly
impacting visibility in Class I areas to install additional controls by December
31, 2017. However, the FDEP has not determined the level of additional controls
PEF may have to implement. The outcome of these matters cannot be
predicted.




Compliance
Strategy




Both PEC
and PEF have been developing an integrated compliance strategy to meet the
requirements of the CAIR, the CAVR, mercury regulation and related air quality
regulations. The air quality controls installed to comply with the requirements
of the NOx SIP Call Rule under Section 110 of the Clean Air Act (NOx SIP Call)
and Clean Smokestacks Act resulted in a reduction of the costs to meet the CAIR
requirements for our North Carolina units at PEC.




PEC has
completed installation of controls to meet the NOx SIP Call requirements. The
NOx SIP Call is not applicable to sources in Florida. Expenditures for the NOx
SIP Call included the cost to install NOx controls under programs by North
Carolina and South Carolina to comply with the federal eight-hour ozone
standard.




The FPSC
approved PEF’s petition to develop and implement an Integrated Clean Air
Compliance Plan to comply with the CAIR, CAMR and CAVR and for recovery of
prudently incurred costs necessary to achieve this strategy through the ECRC
(see discussion above regarding the vacating of the CAMR and remanding of the
CAIR). PEF’s most recent filing with the FPSC, filed on April 1, 2009, seeks
approval for true-up of final 2008 environmental costs and included a review of
the Integrated Clean Air Compliance Plan, which reconfirmed the efficacy of the
recommended plan and included an estimated total project cost of approximately
$1.2 billion to be spent through 2016, to plan, design, build and install
pollution control equipment at the Anclote and Crystal River plants. Additional
costs may be incurred if pollution controls are required in order to comply with
the requirements of the CAVR, as discussed above, or to meet revised compliance
requirements of a revised or new implementing rule for




81




the CAIR.
Subsequent rule interpretations, increases in the underlying material, labor and
equipment costs, equipment availability, or the unexpected acceleration of
compliance dates, among other things, could result in significant increases in
our estimated costs to comply and acceleration of some projects. The outcome of
this matter cannot be predicted.




Environmental Compliance
Cost Estimates




Environmental
compliance cost estimates are dependent upon a variety of factors and, as such,
are highly uncertain and subject to change. Factors impacting our environmental
compliance cost estimates include new and frequently changing laws and
regulations; the impact of legal decisions on environmental laws and
regulations; changes in the demand for, supply of and costs of labor and
materials; changes in the scope and timing of projects; various design, technology
and new generation options; and projections of fuel sources, prices,
availability and security. Costs to comply with environmental laws and
regulations are eligible for regulatory recovery through either base rates or
cost-recovery clauses. The outcome of future petitions for recovery cannot be
predicted. Our estimates of capital expenditures to comply with environmental
laws and regulations are subject to periodic review and revision and may vary
significantly. We cannot predict the impact that the EPA’s further CAIR
proceedings will have on our compliance with the CAVR requirements and will
continue to reassess our plans and estimated costs to comply with the CAVR. The
timing and extent of the costs for future projects will depend upon final
compliance strategies.




The
following tables contain information about our current estimates of capital
expenditures to comply with environmental laws and regulations described above.
Amounts presented in the tables exclude AFUDC.




Progress
      EnergyAir and Water Quality Estimated
      Required Environmental Expenditures  (in
      millions)
                  
                  Estimated
      Timetable
                  
                  
                  Total
      Estimated Expenditures
                  
                  
                  Cumulative
      Spent through March 31, 2009Clean
      Smokestacks Act(a)
                  
                  
                  2002
      – 2013
                  
                  
                  $
                  1,400
                  
                  
                  $
                  1,027In-process
      CAIR projects(b)
                  
                  
                  2005
      – 2010
                  
                  
                  
                  1,200
                  
                  
                  
                  923CAVR(c)
                  
                  
                  –
      2017
                  
                  
                  
                  –
                  
                  
                  
                  –Mercury
      regulation(d)
                  
                  
                  2006
      – 2017
                  
                  
                  
                  –
                  
                  
                  
                  5Total
      air quality
                  
                  
                  
                  
                  
                  
                  2,600
                  
                  
                  
                  1,955Clean
      Water Act Section 316(b)(e)
                  
                  
                  
                  
                  
                  
                  –
                  
                  
                  
                  –Total
      air and water quality
                  
                  
                  
                  
                  
                  $
                  2,600
                  
                  
                  $
                  1,955





PECAir and Water Quality Estimated
      Required Environmental Expenditures  (in
      millions)
                  
                  Estimated
      Timetable
                  
                  
                  Total
      Estimated Expenditures
                  
                  
                  Cumulative
      Spent through March 31, 2009Clean
      Smokestacks Act(a)
                  
                  
                  2002
      – 2013
                  
                  
                  $
                  1,400
                  
                  
                  $
                  1,027In-process
      CAIR projects(b)
                  
                  
                  2005
      – 2008
                  
                  
                  
                  –
                  
                  
                  
                  –CAVR(c)
                  
                  
                  –
      2017
                  
                  
                  
                  –
                  
                  
                  
                  –Mercury
      regulation(d)
                  
                  
                  2006
      – 2017
                  
                  
                  
                  –
                  
                  
                  
                  5Total
      air quality
                  
                  
                  
                  
                  
                  
                  1,400
                  
                  
                  
                  1,032Clean
      Water Act Section 316(b)(e)
                  
                  
                  
                  
                  
                  
                  –
                  
                  
                  
                  –Total
      air and water quality
                  
                  
                  
                  
                  
                  $
                  1,400
                  
                  
                  $
                  1,032




82




PEFAir and Water Quality Estimated
      Required Environmental Expenditures  (in
      millions)
                  
                  Estimated
      Timetable
                  
                  
                  Total
      Estimated Expenditures
                  
                  
                  Cumulative
      Spent through March 31, 2009In-process
      CAIR projects(b)
                  
                  
                  2005
      – 2010
                  
                  
                  $
                  1,200
                  
                  
                  $
                  923CAVR(c)
                  
                  
                  –
      2017
                  
                  
                  
                  –
                  
                  
                  
                  –Mercury
      regulation(d)
                  
                  
                  
                  
                  
                  
                  –
                  
                  
                  
                  –Total
      air quality
                  
                  
                  
                  
                  
                  
                  1,200
                  
                  
                  
                  923Clean
      Water Act Section 316(b)(e)
                  
                  
                  
                  
                  
                  
                  –
                  
                  
                  
                  –Total
      air and water quality
                  
                  
                  
                  
                  
                  $
                  1,200
                  
                  
                  $
                  923





(a)
            PEC
      is continuing to evaluate various design, technology and new generation
      options that could change expenditures required by the Clean Smokestacks
      Act.


(b)
            PEF
      is continuing construction of its in-process emission control projects.
      Additional compliance plans for PEC and PEF to meet the requirements of a
      revised rule will be determined upon finalization of the rule. See
      discussion under “Clean Air Interstate
Rule.”


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


(d)
            Compliance
      plans to meet the requirements of a revised or new implementing rule will
      be determined upon finalization of the rule. See discussion under “Clean
      Air Mercury Rule.”


(e)
              Compliance
      plans to meet the requirements of a revised or new implementing rule under
      Section 316(b) of the Clean Water Act will be determined upon finalization
      of the rule. See discussion under “Water
  Quality.”




All
environmental compliance projects under the first phase of Clean Smokestacks Act
emission reductions, which included projects at PEC’s Asheville, Lee, Mayo and
Roxboro plants, have been placed in service. The remaining projects to comply
with the second phase of emission reductions, which are smaller in scope, have
not yet begun. These estimates are conceptual in nature and subject to change.
Additional compliance projects requiring material environmental compliance costs
may be implemented in the future.




To date,
expenditures at PEF for CAIR regulation primarily relate to environmental
compliance projects under construction at CR5 and CR4, which are expected to be
placed in service in 2009 and 2010, respectively. As a result of changes in the
scope of work related to estimation of costs for compliance with the CAIR and
the uncertainty regarding the EPA’s further CAIR proceedings, the delisting
determination and the CAMR discussed above, PEF is currently unable to estimate
certain costs of compliance. However, PEF believes that future costs to comply
with new or subsequent rule interpretations could be significant. Compliance
plans and estimated costs to meet the requirements of new regulations will be
determined when those new regulations are finalized.




North Carolina Attorney
General Petition under Section 126 of the Clean Air Act




In March
2004, the North Carolina attorney general filed a petition with the EPA, under
Section 126 of the Clean Air Act, asking the federal government to force
coal-fired power plants in 13 other states, including South Carolina, to reduce
their NOx and SO2 emissions.
The state of North Carolina contends these out-of-state emissions interfere with
North Carolina’s ability to meet national air quality standards for ozone and
particulate matter. In 2006, the EPA issued a final response denying the
petition and the North Carolina attorney general filed a petition in the D.C.
Court of Appeals seeking a review of the agency’s denial. Briefing on the merits
has been completed and oral arguments were heard in early 2009. The outcome of
this matter cannot be predicted.




National Ambient Air Quality
Standards




In 2006,
the EPA announced changes to the National Ambient Air Quality Standards (NAAQS)
for particulate matter. The changes in particulate matter standards did not
result in designation of any additional nonattainment areas in PEC’s or PEF’s
service territories. Environmental groups and 13 states filed a joint petition
with the D.C. Court of Appeals arguing that the EPA's new particulate matter
rule does not adequately restrict levels of particulate matter, especially with
respect to the annual and secondary standards. On February 24, 2009, the D.C.
Court of Appeals remanded the annual and secondary standards to the EPA for
further review and consideration. The outcome of this matter cannot be
predicted.




83




On March
12, 2008, the EPA announced changes to the NAAQS for ground-level ozone. The EPA
revised the 8-hour primary and secondary standards from 0.08 parts per million
to 0.075 parts per million. Depending on air quality improvements expected over
the next several years as current federal requirements are implemented,
additional nonattainment areas may be designated in PEC’s and PEF’s service
territories. Should additional nonattainment areas be designated in our service
territories, we may be required to install additional emission controls at some
of our facilities. On May 27, 2008, a number of states, environmental groups and
industry associations filed petitions against the revised NAAQS in the D.C.
Court of Appeals. The EPA has requested the D.C. Court of Appeals to suspend
proceedings in the case while the EPA reconsiders the level of the NAAQS. The
outcome of this matter cannot be predicted.




New Source
Review




The EPA
is conducting an enforcement initiative related to a number of coal-fired
utility power plants in an effort to determine whether changes at those
facilities were subject to New Source Review requirements or New Source
Performance Standards under the Clean Air Act. We were asked to provide
information to the EPA as part of this initiative and cooperated in supplying
the requested information. The EPA has undertaken civil enforcement actions
against unaffiliated utilities as part of this initiative. Some of these actions
resulted in settlement agreements requiring expenditures by these unaffiliated
utilities, several of which included reported expenditures in excess of $1.0
billion for retrofit of pollution control equipment. These settlement agreements
have generally called for expenditures to be made over extended time periods,
and some of the companies may seek recovery of the related costs through rate
adjustments or similar mechanisms.




Water
Quality




1.
General




As a
result of the operation of certain control equipment needed to address the air
quality issues outlined above, new wastewater streams will be generated at
certain affected facilities. Integration of these new wastewater streams into
the existing wastewater treatment processes is currently ongoing and will result
in permitting, construction and treatment requirements imposed on the Utilities
now and into the future. The future costs of these requirements could be
material to our or the Utilities’ results of operations or financial
position.




2.
Section 316(b) of the Clean Water Act




Section
316(b) of the Clean Water Act (Section 316(b)) requires cooling water intake
structures to reflect the best technology available for minimizing adverse
environmental impacts. The EPA promulgated a rule implementing Section 316(b) in
respect to existing power plants in July 2004.




A number
of states, environmental groups and others sought judicial review of the July
2004 rule. In 2007, the U.S. Court of Appeals for the Second Circuit issued an
opinion and order remanding many provisions of the rule to the EPA and the EPA
suspended the rule pending further rulemaking, with the exception of the
requirement that permitted facilities must meet any requirements under Section
316(b) as determined by the permitting authorities on a case-by-case, best
professional judgment basis. Several parties filed petitions for writ of
certiorari to the U.S. Supreme Court. On April 1, 2009, the U.S. Supreme Court
issued its opinion holding that the EPA, in selecting the “best technology”
pursuant to Section 316(b), does have the authority to reject technology when
its costs are “wholly disproportionate” to the benefits expected. Also, the U.S.
Supreme Court held that EPA’s site-specific variance procedure (contained in the
July 2004 rule) was permissible in that the procedure required testing to
determine whether costs would be “significantly greater than” the benefits
before a variance would be considered. The EPA is expected to publish proposed
rules later in 2009 responding to both the remand by the U.S. Court of Appeals
for the Second Circuit and the U.S. Supreme Court’s opinion. As a result of
these developments, our plans and associated estimated costs to comply with
Section 316(b) will need to be reassessed and determined in accordance with any
revised or new implementing rule once it is established by the EPA. Costs of
compliance with a revised or new implementing rule are expected to be higher,
and could be significantly higher, than estimated costs under the July 2004
rule. Our most recent cost estimates to comply with the July 2004 rule were $60
million to $90 million, including $5 million to $10 million at PEC and $55
million to $80 million at PEF. The outcome of this matter cannot be
predicted.




84




OTHER
ENVIRONMENTAL MATTERS




Global Climate
Change




The Kyoto
Protocol was adopted in 1997 by the United Nations to address global climate
change by reducing emissions of CO2 and other
greenhouse gases. The treaty went into effect on February 16, 2005. The United
States has not adopted the Kyoto Protocol. Growing state, federal and
international attention to global climate change may result in the regulation of
CO2
and other greenhouse gases. The Obama administration has agreed to review
whether or not CO2 emissions
from coal-fired power plants should be regulated. We are preparing for a
carbon-constrained future and are actively engaged in helping shape effective
policies to address the issue. While state-level study groups are active in all
three of our jurisdictions, we continue to believe that this is an issue that
requires a national policy framework – one that provides certainty and
consistency. Our balanced solution as discussed in “Other Matters – Increasing
Energy Demand” is a comprehensive plan to meet the anticipated demand in the
Utilities’ service territories and provides a solid basis for slowing and
reducing CO2 emissions
by focusing on energy efficiency, alternative energy and state-of-the-art power
generation. We issued our latest report on global climate change in the second
quarter of 2008, which further evaluates and states our position on this dynamic
issue.




There are
ongoing efforts to reach a new international climate change treaty to succeed
the Kyoto Protocol. Reductions in CO2 emissions
to the levels specified by the Kyoto Protocol, potential new international
treaties or federal or state proposals could be materially adverse to our
financial position or results of operations if associated costs of control or
limitation cannot be recovered from ratepayers. The cost impact of legislation
or regulation to address global climate change would depend on the specific
legislation or regulation enacted and cannot be determined at this time. As
discussed under “Other Matters – Regulatory Environment,” in 2008 the state of
Florida passed
comprehensive energy legislation, which includes a directive that the FDEP
develop rules to establish a cap-and-trade program to regulate greenhouse gas
emissions that would be presented to the legislature no earlier than January
2010.




On April
2, 2007, the U.S. Supreme Court ruled that the EPA has the authority under the
Clean Air Act to regulate CO2 emissions
from new automobiles. On April 2, 2008, 18 states and 11 environmental groups
filed an action in the D.C. Court of Appeals against the EPA Administrator
seeking an order requiring the EPA to make a determination within 60 days of
whether greenhouse gas emissions endanger public health and welfare. The D.C.
Court of Appeals denied the petition on June 26, 2008. On April 17, 2009, the
EPA issued a proposed endangerment finding under the Clean Air Act, which
identified six greenhouse gases (carbon dioxide, methane, nitrous oxide,
hydrofluorocarbons, perfluorocarbons and sulfur hexafluoride) that pose a
potential threat to human health and welfare. The proposed finding now moves to
a public comment period after which the EPA will make a final determination. The
outcome of this matter cannot be predicted.




Prior to
2009, the EPA received waiver requests from a number of states to allow those
states to set standards for CO2 emissions
from new vehicles. The EPA denied those requests. On January 26, 2009, the Obama
administration requested the EPA to review its earlier denials of waiver
requests by states to regulate CO2 emissions
from vehicles. The impact of this development cannot be predicted.




NEW
ACCOUNTING STANDARDS




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




85




PEC




The
following MD&A and the information incorporated herein by reference contain
forward-looking statements that involve estimates, projections, goals,
forecasts, assumptions, risks and uncertainties that could cause actual results
or outcomes to differ materially from those expressed in the forward-looking
statements. Please review “Safe Harbor for Forward-Looking Statements” included
within this Form 10-Q and Item 1A, “Risk Factors” to the 2008 Form 10-K for a
discussion of the factors that may impact any such forward-looking statements
made herein.




RESULTS OF
OPERATIONS




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




LIQUIDITY AND CAPITAL
RESOURCES




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




Net cash
provided by operating activities decreased $22 million for the three months
ended March 31, 2009, when compared to the corresponding period in the prior
year. The decrease was primarily due to the $55 million decrease from accounts
payable, primarily driven by the timing of purchases and payments to vendors; a
$28 million increase in inventory purchases, primarily due to higher priced
coal; and a $23 million increase in accounts receivable driven by higher
revenues. These impacts were partially offset by changes in income taxes,
primarily due to the receipt of a $70 million federal income tax refund, and a
$19 million increase in the recovery of deferred fuel costs due to higher fuel
rates.




Net cash
used by investing activities decreased $24 million for the three months ended
March 31, 2009, when compared to the corresponding period in the prior year. The
decrease was primarily due a $20 million decrease in advances to affiliated
companies and a $13 million decrease in nuclear fuel additions. The decrease in
nuclear fuel additions was driven by higher purchases of nuclear fuel in 2008.
These impacts were partially offset by an $8 million increase in gross property
additions.





Net cash
used by financing activities increased $271 million for the three months ended
March 31, 2009, when compared to the corresponding period in the prior year. The
increase was primarily due to 2009 activity, which included the $400 million
payment at maturity of PEC’s 5.95% Senior Notes, the $200 million in dividends
paid to the Parent and the $110 million repayment of commercial paper
outstanding. These impacts were partially offset by an increase in the proceeds
from the issuance of long-term debt and the $154 million repayment of advances
from affiliates in 2008. PEC issued $600 million in long-term debt in 2009
compared to a $325 million issuance in 2008. PEC’s 2009 financing activities are
further described under Progress Energy’s MD&A, “Liquidity and Capital
Resources.”




OFF-BALANCE SHEET
ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS




PEC’s
off-balance sheet arrangements and contractual obligations are described
below.




MARKET
RISK AND DERIVATIVES




Under its
risk management policy, PEC may use a variety of instruments, including swaps,
options and forward contracts, to manage exposure to fluctuations in commodity
prices and interest rates. See Note 11 and Item 3, “Quantitative and Qualitative
Disclosures about Market Risk” of this Form 10-Q, for a discussion of market
risk and derivatives.




CONTRACTUAL
OBLIGATIONS




This
information is incorporated herein by  reference to "Contractual
Obligations" in Progress Energy's MD&A, insofar as it relates to
PEC.




86




OTHER
MATTERS




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





87




PEF




The
following MD&A and the information incorporated herein by reference contain
forward-looking statements that involve estimates, projections, goals,
forecasts, assumptions, risks and uncertainties that could cause actual results
or outcomes to differ materially from those expressed in the forward-looking
statements. Please review “Safe Harbor for Forward-Looking Statements” included
within this Form 10-Q and Item 1A, “Risk Factors” to the 2008 Form 10-K for a
discussion of the factors that may impact any such forward-looking statements
made herein.




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




RESULTS OF
OPERATIONS




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




LIQUIDITY AND CAPITAL
RESOURCES




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




Net cash
provided by operating activities decreased $158 million for the three months
ended March 31, 2009, when compared to the corresponding period in the prior
year. The decrease was primarily due to a $204 million decrease resulting from
cash collateral posted with counterparties on derivative contracts discussed
under Progress Energy’s MD&A, “Liquidity and Capital Resources;” an $83
million decrease from accounts payable and payables to affiliated companies
driven by the timing of payments to vendors and higher payments for fuel
purchases due to increased fuel costs; a $50 million increase in accounts
receivable driven by higher revenues; and a $35 million increase in inventory
purchases. These impacts were partially offset by an $85 million increase in the
recovery of deferred fuel costs due to higher fuel rates, an $80 million
increase in the recovery of nuclear construction costs under Florida’s nuclear
cost-recovery rule, and a $34 million decrease in long-term emission
allowance purchases.




Net cash
used by investing activities increased $176 million for the three months ended
March 31, 2009, when compared to the corresponding period in the prior year. The
increase was primarily due a $149 million decrease in settlements of advances to
affiliates, a $16 million increase in capital expenditures for utility property
additions, and a $9 million increase in nuclear fuel additions. The increase in
property additions was driven by a $138 million increase in nuclear projects,
partially offset by an $85 million decrease in environmental compliance spending
and a $50 million decrease in spending for repowering the Bartow plant to more
efficient natural gas-burning technology.





Net cash
provided by financing activities increased $342 million for the three months
ended March 31, 2009, when compared to the corresponding period in the prior
year. The increase was primarily due a $347 million change in advances from
affiliates, a $155 million contribution from the Parent and the payment at
maturity of $80 million of first mortgage bonds in 2008. These impacts were
partially offset by the $241 million repayment of commercial paper outstanding.
PEF’s 2009 financing activities are further described under Progress Energy’s
MD&A, “Liquidity and Capital Resources.”




OFF-BALANCE SHEET
ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS




PEF’s
off-balance sheet arrangements and contractual obligations are described
below.




MARKET
RISK AND DERIVATIVES




Under its
risk management policy, PEF may use a variety of instruments, including swaps,
options and forward contracts, to manage exposure to fluctuations in commodity
prices and interest rates. See Note 11 and Item 3, “Quantitative and Qualitative
Disclosures about Market Risk” of this Form 10-Q, for a discussion of market
risk and derivatives.




88




CONTRACTUAL
OBLIGATIONS




This
information is incorporated herein by reference to "Contractual Obligations" in
Progress Energy's MD&A, insofar as it relates to PEF.




OTHER
MATTERS




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





89





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 minimize such risk by performing credit and financial reviews
using a combination of financial analysis and publicly available credit ratings
of such counterparties (See Note 11).  Both PEC and PEF also have limited
counterparty exposure from commodity hedges (primarily gas and oil hedges) by
spreading concentration risk over a number of counterparties.




The
following disclosures about market risk contain forward-looking statements that
involve estimates, projections, goals, forecasts, assumptions, risks and
uncertainties that could cause actual results or outcomes to differ materially
from those expressed in the forward-looking statements. Please review Item 1A,
“Risk Factors” to the 2008 Form 10-K, and Item 1A, “Risk Factors” found within
Part II and “Safe Harbor for Forward-Looking Statements” included within this
Form 10-Q for a discussion of the factors that may impact any such
forward-looking statements made herein.




Certain
market risks are inherent in our financial instruments, which arise from
transactions entered into in the normal course of business. Our primary
exposures are changes in interest rates with respect to our long-term debt and
commercial paper, fluctuations in the return on marketable securities with
respect to our 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, 2008.




INTEREST RATE
RISK




Our
exposure to changes in interest rates from fixed rate and variable rate
long-term debt at March 31, 2009, has changed from December 31, 2008. The total
notional amount of fixed rate long-term debt at March 31, 2009, was $10.295
billion, with an average interest rate of 6.16% and fair market value of $10.7
billion. The total notional amount of fixed rate long-term debt at December 31,
2008, was $9.346 billion, with an average interest rate of 6.17% and fair market
value of $9.9 billion. The total notional amount of variable rate long-term debt
at March 31, 2009, was $961 million, with an average interest rate of 1.22% and
fair market value of $1.0 billion. The total notional amount of variable rate
long-term debt at December 31, 2008, was $1.061 billion, with an average
interest rate of 2.27% and fair market value of $1.1 billion.




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, 2009, and December 31, 2008, approximately
13 percent and 18 percent, respectively, of consolidated debt was in floating
rate mode.




Based on
our variable rate long-term debt balances at March 31, 2009, a 100 basis point
change in interest rates would result in an annual interest expense change of
approximately $10 million. Based on our variable rate short-term debt balances
at March 31, 2009, a 100 basis point change in interest rates would result in an
annual interest expense change of approximately $6 million.




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




90




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




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




In
accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging
Activities” (SFAS No. 133), interest rate derivatives that qualify as hedges are
separated into one of two categories, cash flow hedges or fair value hedges.
Cash flow hedges are used to reduce exposure to changes in cash flow due to
fluctuating interest rates. Fair value hedges are used to reduce exposure to
changes in fair value due to interest rate changes.




The
following table summarizes the terms, fair market values and exposures of our
interest rate derivative instruments. All of the positions included in the table
consist of forward starting swaps used to mitigate exposure to interest rate
risk in anticipation of future debt issuances.




Cash
      Flow Hedges (dollars in millions)
                            
                            Notional
      Amount
                            
                            
                            Pay
                            
                            Receive
      (a)
                            
                            Fair
      Value
                            
                            
                            Exposure
      (b)ParentRisk hedged at March 31,
    2009Anticipated
      10-year debt issue (c)
                            
                            $
                            50
                            
                            
                            
                            3.36
                            %
                            3-month
      LIBOR
                            
                            $
                            –
                            
                            
                            $
                            (1
                            )Risk hedged at December 31,
      2008Anticipated
      10-year debt issue (d)
                            
                            $
                            200
                            
                            
                            
                            4.36
                            %
                            3-month
      LIBOR
                            
                            $
                            (30
                            )
                            
                            $
                            (5
                            )PECRisk hedged at March 31,
    2009Anticipated
      10-year debt issue (e)
                            
                            $
                            50
                            
                            
                            
                            3.49
                            %
                            3-month
      LIBOR
                            
                            $
                            1
                            
                            
                            $
                            (1
                            )Risk hedged at December 31,
      2008Anticipated
      10-year debt issue (f)
                            
                            $
                            250
                            
                            
                            
                            4.18
                            %
                            3-month
      LIBOR
                            
                            $
                            (35
                            )
                            
                            $
                            (6
                            )PEFRisk hedged at March 31,
    2009Anticipated
      10-year debt issue (g)
                            
                            $
                            50
                            
                            
                            
                            3.16
                            %
                            3-month
      LIBOR
                            
                            $
                            –
                            
                            
                            $
                            (1
                            )Risk hedged at December 31,
      2008:
                            
                            None


(a)
              3-month
      LIBOR rate was 1.19% at March 31, 2009, and 1.43% at December 31,
      2008.


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


(c)
              Anticipated
      10-year debt issue hedge executed January 2009 matures on March 1, 2021,
      and requires mandatory cash settlement on March 1,
  2011.


(d)
              Anticipated
      10-year debt issue hedges were terminated on March 16, 2009, in
      conjunction with the Parent’s issuance of $450 million of 7.05% Senior
      Notes due 2019.


(e)
              Anticipated
      10-year debt issue hedge executed January 2009 matures on July 16, 2022,
      and requires mandatory cash settlement on July 16,
  2012.


(f)
              Anticipated
      10-year debt issue hedges were terminated on January 8, 2009, in
      conjunction with PEC’s issuance of $600 million 5.30% First Mortgage Bonds
      due 2019.


(g)
              Anticipated
      10-year debt issue hedge executed January 2009 matures on June 1, 2020,
      and requires mandatory cash settlement on June 1,
  2010.




91




MARKETABLE SECURITIES PRICE
RISK




At March
31, 2009, and December 31, 2008, the fair value of our nuclear decommissioning
trust funds was $1.044 billion and $1.089 billion, respectively, including $651
million and $672 million, respectively, for PEC and $393 million and $417
million, respectively, for PEF. The accounting for nuclear decommissioning
recognizes that the Utilities’ regulated electric rates provide for recovery of
these costs net of any trust fund earnings, and, therefore, fluctuations in
trust fund marketable security returns do not affect earnings.




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, 2009, and December 31, 2008, the
fair value of CVOs was $27 million and $34 million, respectively. We perform
sensitivity analyses to estimate our exposure to the market risk of the CVOs.
The sensitivity analysis performed on the CVOs uses quoted prices obtained from
brokers or quote services to measure the potential loss in earnings from a
hypothetical 10 percent adverse change in market prices over the next 12 months.
A hypothetical 10 percent increase in the March 31, 2009, market price would
result in a $3 million increase in the fair value of the CVOs and a
corresponding increase in the CVO liability.




COMMODITY PRICE
RISK




We are
exposed to the effects of market fluctuations in the price of natural gas, coal,
fuel oil, electricity and other energy-related products marketed and purchased
as a result of our ownership of energy-related assets. Our exposure to these
fluctuations is significantly limited by the cost-based regulation of the
Utilities. Each state commission allows electric utilities to recover certain of
these costs through various cost-recovery clauses to the extent the respective
commission determines that such costs are prudent. Therefore, while there may be
a delay in the timing between when these costs are incurred and when these costs
are recovered from the ratepayers, changes from year to year have no material
impact on operating results. In addition, most of our long-term power sales
contracts shift substantially all fuel price risk to the purchaser.




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




We
perform sensitivity analyses to estimate our exposure to the market risk of our
derivative commodity instruments that are not eligible for recovery from
ratepayers. At March 31, 2009, substantially all derivative commodity instrument
positions were subject to retail regulatory treatment.




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




ECONOMIC
DERIVATIVES




Derivative
products, primarily natural gas and oil contracts, may be entered into from time
to time for economic hedging purposes. While management believes the economic
hedges mitigate exposures to fluctuations in commodity prices, these instruments
are not designated as hedges for accounting purposes and are monitored
consistent with trading positions.




The
Utilities have derivative instruments related to their exposure to price
fluctuations on fuel oil and natural gas purchases. Substantially all of these
instruments receive regulatory accounting treatment. Related unrealized gains
and losses are recorded in regulatory liabilities and regulatory assets,
respectively, on the Balance Sheets until the contracts are settled. After
settlement of the derivatives and the fuel is consumed, realized gains or losses
are passed through the fuel cost-recovery clause. During the quarter ended March
31, 2009, PEC recorded a net realized loss of $18 million. PEC’s net realized
gain was not material during the quarter ended March 31, 2008. During the
quarters ended March 31, 2009 and 2008, PEF recorded a net realized loss of $109
million and a net realized gain of $16 million, respectively.




Certain
of our hedge agreements may result in the receipt of, or posting of, derivative
collateral with our counterparties, depending on the daily derivative position.
Fluctuations in commodity prices that lead to our return of collateral received
and/or our posting of collateral with our counterparty negatively impact our
liquidity. We




92




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




At March
31, 2009, the fair value of PEC’s commodity derivative instruments was recorded
as a $57 million short-term derivative liability position included in derivative
liabilities and $72 million long-term derivative liability position included in
other liabilities and deferred credits on the PEC Consolidated Balance Sheet. At
December 31, 2008, the fair value of such instruments was recorded as a $45
million short-term derivative liability position included in derivative
liabilities and a $54 million long-term derivative liability position included
in other liabilities and deferred credits on the PEC Consolidated Balance Sheet.
Certain counterparties have held cash collateral with PEC in support of these
instruments. PEC had a cash collateral asset included in prepayments and other
current assets of $28 million and $18 million on the PEC Consolidated Balance
Sheet at March 31, 2009 and December 31, 2008, respectively.




At March
31, 2009, the fair value of PEF’s commodity derivative instruments was recorded
as a $5 million short-term derivative asset position included in prepayments and
other current assets, a $496 million short-term liability position included in
current derivative liabilities, and a $275 million long-term derivative
liability position included in derivative liabilities on the PEF Balance Sheet.
At December 31, 2008, the fair value of such instruments was recorded as a $9
million short-term derivative asset position included in prepayments and other
current assets, a $1 million long-term derivative asset position included in
other assets and deferred debits, a $380 million short-term liability position
included in current derivative liabilities, and a $209 million long-term
derivative liability position included in derivative liabilities on the PEF
Balance Sheet. Certain counterparties have held cash collateral in support of
these instruments. Due to the significant decline in natural gas prices
since December 31, 2008, PEF's cash collateral asset included in derivative
collateral posted was $535 million and $335 million on the PEF Balance
Sheet at March 31, 2009 and December 31, 2008, respectively.




CASH
FLOW HEDGES




The
Utilities designate a portion of commodity derivative instruments as cash flow
hedges under SFAS No. 133. From time to time we hedge exposure to market risk
associated with fluctuations in the price of power for our forecasted sales.
Realized gains and losses are recorded net in operating revenues. We also hedge
exposure to market risk associated with fluctuations in the price of fuel for
fleet vehicles. Realized gains and losses are recorded net as part of fleet
vehicle costs. At March 31, 2009 and December 31, 2008, neither we nor the
Utilities had material outstanding positions in such contracts. The ineffective
portion of commodity cash flow hedges was not material to our or the Utilities’
results of operations for the three months ended March 31, 2009 and
2008.




At March
31, 2009 and December 31, 2008, the amount recorded in our or the Utilities
accumulated other comprehensive income related to commodity cash flow hedges was
not material.




PEC




The
information required by this item is incorporated herein by reference to the
“Quantitative and Qualitative Disclosures about Market Risk” discussed above
insofar as it relates to PEC.




PEC has
certain market risks inherent in its financial instruments, which arise from
transactions entered into in the normal course of business. PEC’s primary
exposures are changes in interest rates with respect to long-term debt and
commercial paper, fluctuations in the return on marketable securities with
respect to its nuclear decommissioning trust funds, and changes in energy
related commodity prices. Other than discussed above, PEC’s exposure to these
risks has not materially changed since December 31, 2008.




PEF




Other
than as discussed above, the information called for by Item 3 is omitted
pursuant to Instruction H(2)(c) to Form 10-Q (Omission of Information by Certain
Wholly Owned Subsidiaries).


93




ITEM
4.                     CONTROLS AND
PROCEDURES




PROGRESS
ENERGY




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




There has
been no change in our internal control over financial reporting during the
quarter ended March 31, 2009, that has materially affected, or is reasonably
likely to materially affect, our internal control over financial
reporting.




ITEM
4T.       
CONTROLS
AND PROCEDURES
  PEC
  Pursuant
to the Securities Exchange Act of 1934, PEC carried out an evaluation, with the
participation of its management, including PEC’s Chief Executive Officer and
Chief Financial Officer, of the effectiveness of PEC’s disclosure controls and
procedures (as defined under the Securities Exchange Act of 1934) as of the end
of the period covered by this report. Based upon that evaluation, PEC’s Chief
Executive Officer and Chief Financial Officer concluded that its disclosure
controls and procedures are effective to ensure that information required to be
disclosed by PEC in the reports that it files or submits under the Exchange Act,
is recorded, processed, summarized and reported within the time periods
specified in the SEC's rules and forms, and that such information is accumulated
and communicated to PEC’s management, including the Chief Executive Officer and
Chief Financial Officer, as appropriate, to allow timely decisions regarding
required disclosure.
  There has
been no change in PEF’s internal control over financial reporting during the
quarter ended March 31, 2009, that has materially affected, or is reasonably
likely to materially affect, its internal control over financial
reporting.
 PEF
  Pursuant
to the Securities Exchange Act of 1934, PEF carried out an evaluation, with the
participation of its management, including PEF’s Chief Executive Officer and
Chief Financial Officer, of the effectiveness of PEF’s disclosure controls and
procedures (as defined under the Securities Exchange Act of 1934) as of the end
of the period covered by this report. Based upon that evaluation, PEF’s Chief
Executive Officer and Chief Financial Officer concluded that its disclosure
controls and procedures are effective to ensure that information required to be
disclosed by PEF in the reports that it files or submits under the Exchange Act,
is recorded, processed, summarized and reported within the time periods
specified in the SEC's rules and forms, and that such information is accumulated
and communicated to PEF’s management, including the Chief Executive Officer and
Chief Financial Officer, as appropriate, to allow timely decisions regarding
required disclosure.
  There has
been no change in PEF’s internal control over financial reporting during the
quarter ended March 31, 2009, that has materially affected, or is reasonably
likely to materially affect, its internal control over financial
reporting.
   94







PART
II.  OTHER INFORMATION





ITEM
1.LEGAL
PROCEEDINGS




Legal
aspects of certain matters are set forth in PART I, Item 1 (See Note
15C).




ITEM
1A.                         
 RISK
FACTORS




In
addition to the risk factor disclosed below and the other information set forth
in this report, you should carefully consider the factors discussed in Part I,
Item 1A. Risk Factors to the 2008 Form 10-K, which could materially affect our
business, financial condition or future results. The risks described herein and
in the 2008 Form 10-K are not the only risks facing us. Additional risks and
uncertainties not currently known to us or that we currently deem to be
immaterial also may materially adversely affect our business, financial
condition and/or operating results.




Impairment of goodwill could have a
significant negative impact on our financial condition and results of
operations.




We
account for goodwill in accordance with SFAS No. 142, “Goodwill and Other
Intangible Assets” , which requires that goodwill be tested for impairment at
least annually and more frequently when indicators of impairment exist. All of
our goodwill is allocated to our utility segments and goodwill impairment tests
are performed at the utility segment level.





We
calculate the fair value of our utility segments by considering various factors,
including valuation studies based primarily on income and market approaches.
These calculations are dependent on subjective factors such as management’s
estimate of future cash flows and the selection of appropriate discount and
growth rates from a marketplace participant’s perspective. These underlying
assumptions and estimates are made as of a point in time; subsequent changes,
particularly changes in management’s estimate of future cash flows and the
discount rates, interest rates and growth rates, could result in a future
impairment charge to goodwill. Impairment of our recorded goodwill could result
in earnings volatility and an increase in our leverage, which could trigger a
downgrade of our credit ratings leading to higher borrowing costs.







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




RESTRICTED
STOCK UNIT AWARD PAYOUTS




(a)
            Securities
      Delivered. On March 2, 2009, March 16, 2009 and March 20, 2009,
      14,708 shares, 505 shares and 62 shares, respectively, of our common stock
      were delivered to certain former employees pursuant to the terms of the
      Progress Energy 2002 and 2007 Equity Incentive Plans (individually and
      collectively, the “EIP,”) which have been approved by Progress Energy’s
      shareholders.  Additionally, on March 18, 2009 and March 20,
      2009, 135,487 shares and 194,234 shares respectively, of our common stock
      were delivered to certain current employees pursuant to the terms of the
      EIP.  The shares of common stock delivered pursuant to the EIP
      were newly issued shares of Progress
Energy.




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




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




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






95




PERFORMANCE
SHARE SUB-PLAN AWARD PAYOUTS




(a)
            Securities
      Delivered.  On March 23, 2009, 239,954 shares of our
      common stock were delivered to employees pursuant to the terms of the
      EIP.  Additionally, on March 31, 2009, 492 shares of our common
      stock were delivered to a former employee pursuant to the terms of the
      EIP. The shares of common stock delivered pursuant to the EIP were newly
      issued shares of Progress Energy.




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




(c)
            Consideration.  The
      performance share awards were granted to provide an incentive to the
      current and former employees to exert their utmost efforts on our behalf
      and thus enhance our performance while aligning the employees’ interests
      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 2009




Period
                                    (a)
                                      Total
      Number of Shares
                                      (or
      Units) Purchased(1)(2)(3)(4)
                                    (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
                                    177,073
                                    $38.3467
                                    N/A
                                    N/AFebruary
      1– February 28
                                    580,400
                                    37.6673
                                    N/A
                                    N/AMarch
      1– March 31
                                    442,044
                                    35.6940
                                    N/A
                                    N/ATotal
                                    1,199,517
                                    $37.0404
                                    N/A
                                    N/A





(1)
            At
      March 31, 2009, Progress Energy does not have any publicly announced plans
      or programs to purchase shares of its common
  stock.


(2)
            The
      plan administrator purchased 654,773 shares of our common stock in
      open-market transactions to meet share delivery obligations under the
      Progress Energy 401(k) Savings and Stock Ownership
  Plan.


(3)
            The
      plan administrator purchased 323,200 shares of our common stock in
      open-market transactions to meet share delivery obligations under the
      Savings Plan for Employees of Florida Progress
  Corporation.


(4)
            The
      plan administrator purchased 16,892 shares of our common stock in
      open-market transactions to meet share delivery obligations under the
      Progress Energy Investor Plus
Plan.


96





ITEM
6.           
EXHIBITS




(a)
            Exhibits





Exhibit
      Number
            Description
            Progress
              Energy
            PEC
            PEF10(a)
            Amended
      and Restated Supplemental Senior Executive Retirement Plan of Progress
      Energy, Inc., effective January 1, 2009
            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





97





SIGNATURES




Pursuant
to requirements of the Securities Exchange Act of 1934, the registrants have
duly caused this report to be signed on their behalf by the undersigned
thereunto duly authorized.




PROGRESS ENERGY, INC.CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS
      ENERGY CAROLINAS, INC.FLORIDA POWER CORPORATION d/b/a PROGRESS ENERGY
      FLORIDA, INC.Date:
      May 8, 2009
                      (Registrants)By: /s/ Mark F. MulhernMark
      F. MulhernSenior
      Vice President and Chief Financial OfficerBy: /s/ Jeffrey M. StoneJeffrey
      M. StoneChief
      Accounting Officer and ControllerProgress
      Energy, Inc.Chief
      Accounting OfficerCarolina
      Power & Light Company d/b/a Progress Energy Carolinas,
      Inc.Florida
      Power Corporation d/b/a Progress Energy Florida,
  Inc.





98