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, 2008
 
 OR
 
 oTRANSITION
REPORT PURSUANT TO SECTION 13 OR
 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
 
 For the
transition period
from                      to                    .
 
 
 Commission
      File Number
              Exact
      name of registrants as specified in their charters, states of
      incorporation,
                addresses
      of principal executive offices,and
      telephone numbers
              I.R.S.
      Employer Identification Numberlogo1-15929
              Progress
      Energy, Inc.
                410
      South Wilmington Street
                Raleigh,
      North Carolina 27601-1748
                Telephone:   (919)
      546-6111
                State
      of Incorporation: North Carolina
              56-21554811-3382
              Carolina
      Power & Light Company
                d/b/a
      Progress Energy Carolinas, Inc.
                410
      South Wilmington Street
                Raleigh,
      North Carolina  27601-1748
                Telephone:   (919)
      546-6111
                State
      of Incorporation: North Carolina
              56-01654651-3274
              Florida
      Power Corporation
                d/b/a
      Progress Energy Florida, Inc.
                299
      First Avenue North
                St.
      Petersburg, Florida  33701
                Telephone:   (727)
      820-5151
                State
      of Incorporation: Florida
              59-0247770
 
 NONE
 (Former
name, former address and former fiscal year, if changed since last
report)
 
 Indicate
by check mark whether each registrant (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrants were
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
 
 Progress
      Energy, Inc. (Progress Energy)
              Yes
              x
              No
              oCarolina
      Power & Light Company (PEC)
              Yes
              x
              No
              oFlorida
      Power Corporation (PEF)
              Yes
              o
              No
              x
 
 1
 Indicate
by check mark whether each registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting company. See
definition of “large accelerated filer,” “accelerated filer” and “smaller
reporting company” in Rule 12b-2 of the Exchange Act.:
 
 Progress
      Energy
              Large
      accelerated filer
              x
              Accelerated
      filer
              oNon-accelerated
      filer
              o
              Smaller
      reporting company
              oPEC
              Large
      accelerated filer
              o
              Accelerated
      filer
              oNon-accelerated
      filer
              x
              Smaller
      reporting company
              oPEF
              Large
      accelerated filer
              o
              Accelerated
      filer
              oNon-accelerated
      filer
              x
              Smaller
      reporting company
              o
 
 Indicate
by check mark whether each registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act).
 
 Progress
      Energy
              Yes
              o
              No
              xPEC
              Yes
              o
              No
              xPEF
              Yes
              o
              No
              x
 
 As of May
5, 2008, each registrant had the following shares of common stock
outstanding:
 
 Registrant
              Description
              SharesProgress
      Energy
              Common
      Stock (Without Par Value)
              261,320,773PEC
              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
      5.
                OTHER
      INFORMATIONITEM
      6.
                EXHIBITSSIGNATURES
  3
 GLOSSARY OF TERMS
 
 We use
the words “Progress Energy,” “we,” “us” or “our” with respect to certain
information to indicate that such information relates to Progress Energy, Inc.
and its subsidiaries on a consolidated basis. When appropriate, the parent
holding company or the subsidiaries of Progress Energy are specifically
identified on an unconsolidated basis as we discuss their various business
activities.
  The
following abbreviations or acronyms are used by the Progress
Registrants:
  TERM
              DEFINITION2007
      Form 10-K
              Progress
      Registrants’ annual report on Form 10-K for the fiscal year ended December
      31, 2007401(k)
              Progress
      Energy 401(k) Savings & Stock Ownership PlanAFUDC
              Allowance
      for funds used during constructionAHI
              Affordable
      housing investmentARO
              Asset
      retirement obligationAnnual
      Average Price
              Average
      wellhead price per barrel for unregulated domestic crude oil for the
      yearAsset
      Purchase Agreement
              Agreement
      by and among Global, Earthco and certain affiliates, and the Progress
      Affiliates as amended on August 23, 2000Audit
      Committee
              Audit
      and Corporate Performance Committee of Progress Energy’s board of
      directorsBART
              Best
      Available Retrofit TechnologyBroad
      River
              Broad
      River LLC’s Broad River FacilityBrunswick
              PEC’s
      Brunswick Nuclear PlantBtu
              British
      thermal unitCAIR
              Clean
      Air Interstate RuleCAMR
              Clean
      Air Mercury RuleCAVR
              Clean
      Air Visibility RuleCCO
              Competitive
      Commercial OperationsCERCLA
      or Superfund
              Comprehensive
      Environmental Response, Compensation and Liability Act of 1980, as
      amendedCeredo
              Ceredo
      Synfuel LLCCIGFUR
              Carolina
      Industrial Group for Fair Utility Rates IIClean
      Smokestacks Act
              North
      Carolina Clean Smokestacks Act, enacted in June 2002Coal
      Mining
              The
      remaining operations of Progress Fuels subsidiaries engaged in the coal
      mining businessCoal
      and Synthetic Fuels
              Former
      business segment that had been primarily engaged in the production and
      sales of coal-based solid synthetic fuels, the operation of synthetic
      fuels facilities for third parties and coal terminal
    servicesthe
      Code
              Internal
      Revenue CodeCO2
              Carbon
      dioxideCOL
              Combined
      licenseColona
              Colona
      Synfuel Limited Partnership, LLLPCorporate
      and Other
              Corporate
      and Other segment includes Corporate as well as other nonregulated
      businessesCR3
              PEF’s
      Crystal River Unit No. 3 Nuclear PlantCR4
      and CR5
              PEF’s
      Crystal River Units No. 4 and 5 coal-fired steam
  turbinesCUCA
              Carolina
      Utility Customers AssociationCVO
              Contingent
      value obligationD.C.
      Court of Appeals
              U.S.
      Court of Appeals for the District of Columbia CircuitDeSoto
              DeSoto
      County Generating Co., LLCDIG
      Issue C20
              FASB
      Derivatives Implementation Group Issue C20, “Interpretation of the Meaning
      of Not Clearly and Closely Related in Paragraph 10(b) regarding Contracts
      with a Price Adjustment Feature”Dixie
      Fuels
              Dixie
      Fuels LimitedDOE
              United
      States Department of Energy
  4
  DSM
              Demand-side
      managementEarthco
              Four
      coal-based solid synthetic fuels limited liability companies of which
      three are wholly ownedECCR
              Energy
      Conservation Cost Recovery ClauseECRC
              Environmental
      Cost Recovery ClauseEIA
              Energy
      Information AgencyEIP
              Equity
      Incentive PlanEPA
              United
      States Environmental Protection AgencyEPACT
              Energy
      Policy Act of 2005EPC
              Engineering,
      procurement and construction contractERO
              Electric
      reliability organizationESOP
              Employee
      Stock Ownership PlanFASB
              Financial
      Accounting Standards BoardFDEP
              Florida
      Department of Environmental ProtectionFERC
              Federal
      Energy Regulatory CommissionFDCA
              Florida
      Department of Community AffairsFGT
              Florida
      Gas Transmission CompanyFIN
      39
              FASB
      Interpretation No. 39, “Offsetting of Amounts Related to Certain
      Contracts”FIN
      45
              FASB
      Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements
      for Guarantees, Including Indirect Guarantees of Indebtedness of
      Others”FIN
      46R
              FASB
      Interpretation No. 46R, “Consolidation of Variable Interest Entities – an
      Interpretation of ARB No. 51”FIN
      47
              FASB
      Interpretation No. 47, “Accounting for Conditional Asset Retirement
      Obligations – an Interpretation of FASB Statement No.
  143”FIN
      48
              FASB
      Interpretation No. 48, “Accounting for Uncertainty in Income
      Taxes”the
      Florida Global Case
              U.S.
      Global, LLC v. Progress Energy, Inc. et alFlorida
      Progress
              Florida
      Progress CorporationFPSC
              Florida
      Public Service CommissionFRCC
              Florida
      Reliability Coordinating CouncilFSP
              FASB
      Staff PositionFSP
      FIN 39-1
              FASB
      Staff Position FIN No. 39-1, “An Amendment of FIN 39, Offsetting of
      Amounts Related to Certain Contracts”Funding
      Corp.
              Florida
      Progress Funding Corporation, a wholly owned subsidiary of Florida
      ProgressGAAP
              Accounting
      principles generally accepted in the United States of
    AmericaGas
              Natural
      gas drilling and production businessthe
      Georgia Contracts
              Full-requirements
      contracts with 16 Georgia electric membership cooperatives formerly
      serviced by CCOGeorgia
      Power
              Georgia
      Power Company, a subsidiary of Southern CompanyGeorgia
      Operations
              Former
      reporting unit consisting of the Effingham, Monroe, Walton and Washington
      nonregulated generation plants in service and the Georgia
      ContractsGlobal
              U.S.
      Global, LLCGridSouth
              GridSouth
      Transco, LLCGulfstream
              Gulfstream
      Gas System, L.L.C.Harris
              PEC’s
      Shearon Harris Nuclear PlantIBEW
              International
      Brotherhood of Electrical WorkersIRS
              Internal
      Revenue ServicekV
              KilovoltkVA
              Kilovolt-amperekWh
              Kilowatt-hoursLevel
      3 Communications
              Level
      3 Communications, Inc.LIBOR
              London
      Inter Bank Offering Rate
  MD&A
              Management’s
      Discussion and Analysis of Financial Condition and Results of Operations
      contained in Part I, Item 2 of this Form 10-QMedicare
      Act
              Medicare
      Prescription Drug, Improvement and Modernization Act of
    2003MGP
              Manufactured
      gas plant
 MW
              MegawattsMWh
              Megawatt-hoursMoody’s
              Moody’s
      Investors Service, Inc.NAAQS
              National
      Ambient Air Quality StandardsNCDWQ
              North
      Carolina Division of Water QualityNCUC
              North
      Carolina Utilities CommissionNEIL
              Nuclear
      Electric Insurance LimitedNERC
              North
      American Electric Reliability CorporationNorth
      Carolina Global Case
              Progress
      Synfuel Holdings, Inc. et al. v. U.S. Global, LLCthe
      Notes Guarantee
              Florida
      Progress’ full and unconditional guarantee of the Subordinated
      NotesNOx
              Nitrogen
      OxidesNOx
      SIP Call
              EPA
      rule which requires 22 states including North Carolina, South Carolina and
      Georgia (but excluding Florida) to further reduce emissions of nitrogen
      oxidesNSR
              New
      Source Review requirements by the EPANRC
              United
      States Nuclear Regulatory CommissionNuclear
      Waste Act
              Nuclear
      Waste Policy Act of 1982NYMEX
              New
      York Mercantile ExchangeO&M
              Operation
      and maintenance expenseOATT
              Open
      Access Transmission TariffOCI
              Other
      comprehensive incomeOPC
              Florida’s
      Office of Public CounselOPEB
              Postretirement
      benefits other than pensionsthe
      Parent
              Progress
      Energy, Inc. holding company on an unconsolidated basisPEC
              Carolina
      Power & Light Company d/b/a Progress Energy Carolinas,
      Inc.PEF
              Florida
      Power Corporation d/b/a Progress Energy Florida, Inc.PESC
              Progress
      Energy Service Company, LLCthe
      Phase-out Price
              Price
      per barrel of unregulated domestic crude oil at which the value of Section
      29/45K tax credits are fully eliminatedPM
      2.5
              EPA
      standard for particulate matter less than 2.5 microns in
      diameterPM
      2.5-10
              EPA
      standard for particulate matter between 2.5 and 10 microns in
      diameterPM
      10
              EPA
      standard for particulate matter less than 10 microns in
      diameterPower
      Agency
              North
      Carolina Eastern Municipal Power AgencyPreferred
      Securities
              7.10%
      Cumulative Quarterly Income Preferred Securities due 2039, Series A issued
      by the TrustPreferred
      Securities Guarantee
              Florida
      Progress’ guarantee of all distributions related to the Preferred
      SecuritiesProgress
      Affiliates
              Five
      affiliated coal-based solid synthetic fuels facilitiesProgress
      Energy
              Progress
      Energy, Inc. and subsidiaries on a consolidated basisProgress
      Registrants
              The
      reporting registrants within the Progress Energy consolidated group.
      Collectively, Progress Energy, Inc., PEC and PEFProgress
      Fuels
              Progress
      Fuels Corporation, formerly Electric Fuels CorporationProgress
      Rail
              Progress
      Rail Services CorporationPRP
              Potentially
      responsible party, as defined in CERCLAPSSP
              Performance
      Share Sub-PlanPT
      LLC
              Progress
      Telecom, LLCPUHCA
      1935
              Public
      Utility Holding Company Act of 1935, as amendedPUHCA
      2005
              Public
      Utility Holding Company Act of 2005PURPA
              Public
      Utilities Regulatory Policies Act of 1978PVI
              Progress
      Energy Ventures, Inc., formerly referred to as Progress Ventures,
      Inc.PWC
              Public
      Works Commission of the City of Fayetteville, North
    CarolinaQF
              Qualifying
      facilityRCA
              Revolving
      credit agreement
  5
  
 REC
              Renewable
      energy certificatesREPS
              North
      Carolina Renewable Energy and Energy Efficiency Portfolio
      StandardReagents
              Commodities
      such as ammonia and limestone used in emissions control
      technologiesRockport
              Indiana
      Michigan Power Company’s Rockport Unit No. 2Robinson
              PEC’s
      Robinson Nuclear PlantROE
              Return
      on equityRowan
              Rowan
      County Power, LLCRSA
              Restricted
      stock awards programRSU
              Restricted
      stock unitRTO
              Regional
      transmission organizationSCPSC
              Public
      Service Commission of South CarolinaSEC
              United
      States Securities and Exchange CommissionSection
      29
              Section
      29 of the CodeSection
      29/45K
              General
      business tax credits earned after December 31, 2005 for synthetic fuels
      production in accordance with Section 29Section
      316(b)
              Section
      316(b) of the Clean Water ActSection
      45K
              Section
      45K of the Code(See
      Note/s “#”)
              For
      all sections, this is a cross-reference to the Combined Notes to the
      Financial Statements contained in PART I, Item 1 of this Form
      10-QSERC
              SERC
      Reliability CorporationSESH
              Southeast
      Supply Header, L.L.C.S&P
              Standard
      & Poor’s Rating ServicesSFAS
              Statement
      of Financial Accounting StandardsSFAS
      No. 5
              Statement
      of Financial Accounting Standards No. 5, “Accounting for
      Contingencies”SFAS
      No. 71
              Statement
      of Financial Accounting Standards No. 71, “Accounting for the Effects of
      Certain Types of Regulation”SFAS
      No. 87
              Statement
      of Financial Accounting Standards No. 87, “Employers’ Accounting for
      Pensions”SFAS
      No. 109
              Statement
      of Financial Accounting Standards No. 109, “Accounting for Income
      Taxes”SFAS
      No. 115
              Statement
      of Financial Accounting Standards No. 115, “Accounting for Certain
      Investments in Debt and Equity Securities”SFAS
      No. 123R
              Statement
      of Financial Accounting Standards No. 123R, “Share-Based
      Payment”SFAS
      No. 133
              Statement
      of Financial Accounting Standards No. 133, “Accounting for Derivative
      Instruments and Hedging Activities”SFAS
      No. 141R
              Statement
      of Financial Accounting Standards No. 141R, “Business
      Combinations”SFAS
      No. 142
              Statement
      of Financial Accounting Standards No. 142, “Goodwill and Other Intangible
      Assets”SFAS
      No. 143
              Statement
      of Financial Accounting Standards No. 143, “Accounting for Asset
      Retirement Obligations”SFAS
      No. 144
              Statement
      of Financial Accounting Standards No. 144, “Accounting for the Impairment
      or Disposal of Long-Lived Assets”SFAS
      No. 157
              Statement
      of Financial Accounting Standards No. 157, “Fair Value
      Measurements”SFAS
      No. 158
              Statement
      of Financial Accounting Standards No. 158, “Employers’ Accounting for
      Defined Benefit Pension and Other Postretirement Plans”SFAS
      No. 159
              Statement
      of Financial Accounting Standards No. 159, “The Fair Value Option for
      Financial Assets and Financial Liabilities – Including an amendment of
      FASB Statement No. 115”SFAS
      No. 160
              Statement
      of Financial Accounting Standards No. 160, “Noncontrolling Interests in
      Consolidated Financial Statements, an amendment of ARB No.
    51”
 SFAS
      No. 161
              Statement
      of Financial Accounting Standards No. 161, “Disclosures About Derivative
      Instruments and Hedging Activities — an amendment of FASB Statement No.
      133”SNG
              Southern
      Natural Gas Company
  6
 SO2
              Sulfur
      dioxide
 Subordinated
      Notes
              7.10%
      Junior Subordinated Deferrable Interest Notes due 2039 issued by Funding
      Corp.Tax
      Agreement
              Intercompany
      Income Tax Allocation AgreementTerminals
              Coal
      terminals and docks in West Virginia and Kentuckythe
      Threshold Price
              Price
      per barrel of unregulated domestic crude oil at which the value of Section
      29/45K tax credits begin to be reducedthe
      Trust
              FPC
      Capital Ithe
      Utilities
              Collectively,
      PEC and PEFWinchester
      Production
              Winchester
      Production Company, Ltd.
  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, changes
in the regulatory environment, meeting increasing energy demand in our service
territories and the impact of environmental regulations.
  Examples
of factors that you should consider with respect to any forward-looking
statements made throughout this document include, but are not limited to, the
following: the impact of fluid and complex laws and regulations, including those
relating to the environment and the Energy Policy Act of 2005 (EPACT); the
anticipated future need for additional baseload generation and associated
transmission facilities in our regulated service territories and the
accompanying regulatory and financial risks; the financial resources and capital
needed to comply with environmental laws and renewable energy portfolio
standards and our ability to recover related eligible costs under cost-recovery
clauses or base rates; our ability to meet current and future renewable energy
requirements; the inherent risks associated with the operation of nuclear
facilities, including environmental, health, regulatory and financial risks; the
impact on our facilities and businesses from a terrorist attack; weather and
drought conditions that directly influence the production, delivery and demand
for electricity; recurring seasonal fluctuations in demand for electricity; the
ability to recover in a timely manner, if at all, costs associated with future
significant weather events through the regulatory process; economic fluctuations
and the corresponding impact on our customers, including downturns in the
housing and consumer credit markets; fluctuations in the price of energy
commodities and purchased power and our ability to recover such costs through
the regulatory process; the Progress Registrants’ ability to control costs,
including operation and maintenance expense (O&M) and large construction
projects; the ability of our subsidiaries to pay upstream dividends or
distributions to the Parent; the ability to successfully access capital markets
on favorable terms; the impact that increases in leverage may have on each of
the Progress Registrants; the Progress Registrants’ ability to maintain their
current credit ratings and the impact on the Progress Registrants’ financial
condition and ability to meet their cash and other financial obligations in the
event their credit ratings are downgraded; our ability to fully utilize tax
credits generated from the previous production and sale of qualifying synthetic
fuels under Internal Revenue Code Section 29/45K (Section 29/45K); the
investment performance of our nuclear decommissioning trust funds and the assets
of our pension and benefit plans; the outcome of any ongoing or future
litigation or similar disputes and the impact of any such outcome or related
settlements; and unanticipated changes in operating expenses and capital
expenditures. Many of these risks similarly impact our nonreporting
subsidiaries.
  These and
other risk factors are detailed from time to time in the Progress Registrants’
filings with the United States Securities and Exchange Commission (SEC). Many,
but not all, of the factors that may impact actual results are discussed in the
Risk Factors section in the Progress Registrants’ annual report on Form 10-K for
the fiscal year ended December 31, 2007 (2007 Form 10-K), which was filed with
the SEC on February 28, 2008, and is updated for material changes, if any, in
this Form 10-Q and in our other SEC filings. All such factors are difficult to
predict, contain uncertainties that may materially affect actual results and may
be beyond our control. New factors emerge from time to time, and it is not
possible for management to predict all such factors, nor can management assess
the effect of each such factor on the Progress Registrants.
   8
  PART
I.  FINANCIAL INFORMATION
 ITEM
1.                  FINANCIAL
STATEMENTS
  PROGRESS
ENERGY, INC.
 UNAUDITED
CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS
 March
31, 2008
 
 UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of
      INCOME(in
      millions except per share data)Three
      months ended March 31
              
              2008
              
              
              2007Operating
      revenues
              
              $
              2,066
              
              
              $
              2,072Operating
      expensesFuel
      used in electric generation
              
              
              697
              
              
              
              736Purchased
      power
              
              
              232
              
              
              
              221Operation
      and maintenance
              
              
              443
              
              
              
              420Depreciation
      and amortization
              
              
              206
              
              
              
              219Taxes
      other than on income
              
              
              121
              
              
              
              124Other
              
              
              2
              
              
              
              1Total
      operating expenses
              
              
              1,701
              
              
              
              1,721Operating
      income
              
              
              365
              
              
              
              351Other
      incomeInterest
      income
              
              
              7
              
              
              
              8Other,
      net
              
              
              18
              
              
              
              11Total
      other income
              
              
              25
              
              
              
              19Interest
      chargesInterest
      charges
              
              
              161
              
              
              
              145Allowance
      for borrowed funds used during construction
              
              
              (8
              )
              
              
              (3
              )Total
      interest charges, net
              
              
              153
              
              
              
              142Income
      from continuing operations before income tax andminority
      interest
              
              
              237
              
              
              
              228Income
      tax expense
              
              
              84
              
              
              
              72Income
      from continuing operations before minority interest
              
              
              153
              
              
              
              156Minority
      interest in subsidiaries’ income, net of tax
              
              
              (4
              )
              
              
              (7
              )Income
      from continuing operations
              
              
              149
              
              
              
              149Discontinued
      operations, net of tax
              
              
              60
              
              
              
              126Net
      income
              
              $
              209
              
              
              $
              275Average
      common shares outstanding – basic
              
              
              259
              
              
              
              254Basic
      earnings per common shareIncome
      from continuing operations
              
              $
              0.58
              
              
              $
              0.59Discontinued
      operations, net of tax
              
              
              0.23
              
              
              
              0.49Net
      income
              
              $
              0.81
              
              
              $
              1.08Diluted
      earnings per common shareIncome
      from continuing operations
              
              $
              0.58
              
              
              $
              0.59Discontinued
      operations, net of tax
              
              
              0.23
              
              
              
              0.49Net
      income
              
              $
              0.81
              
              
              $
              1.08Dividends
      declared per common share
              
              $
              0.615
              
              
              $
              0.610
 
 See
Notes to Progress Energy, Inc. Unaudited Condensed Consolidated Interim
Financial Statements.
  9
  PROGRESS
      ENERGY, INC.UNAUDITED CONDENSED CONSOLIDATED BALANCE
      SHEETS(in
      millions)
              
              March
      31, 2008
              
              
              December
      31, 2007ASSETSUtility
      plantUtility
      plant in service
              
              $
              25,490
              
              
              $
              25,327Accumulated
      depreciation
              
              
              (11,037
              )
              
              
              (10,895
              )Utility
      plant in service, net
              
              
              14,453
              
              
              
              14,432Held
      for future use
              
              
              37
              
              
              
              37Construction
      work in progress
              
              
              2,124
              
              
              
              1,765Nuclear
      fuel, net of amortization
              
              
              372
              
              
              
              371Total
      utility plant, net
              
              
              16,986
              
              
              
              16,605Current
      assetsCash
      and cash equivalents
              
              
              400
              
              
              
              255Short-term
      investments
              
              
              1
              
              
              
              1Receivables,
      net
              
              
              767
              
              
              
              1,167Inventory
              
              
              999
              
              
              
              994Deferred
      fuel cost
              
              
              138
              
              
              
              154Deferred
      income taxes
              
              
              3
              
              
              
              27Derivative
      assets
              
              
              217
              
              
              
              85Assets
      to be divested
              
              
              –
              
              
              
              52Prepayments
      and other current assets
              
              
              73
              
              
              
              94Total
      current assets
              
              
              2,598
              
              
              
              2,829Deferred
      debits and other assetsRegulatory
      assets
              
              
              926
              
              
              
              946Nuclear
      decommissioning trust funds
              
              
              1,313
              
              
              
              1,384Miscellaneous
      other property and investments
              
              
              466
              
              
              
              448Goodwill
              
              
              3,655
              
              
              
              3,655Derivative
      assets
              
              
              210
              
              
              
              119Other
      assets and deferred debits
              
              
              390
              
              
              
              379Total
      deferred debits and other assets
              
              
              6,960
              
              
              
              6,931Total
      assets
              
              $
              26,544
              
              
              $
              26,365CAPITALIZATION
      AND LIABILITIESCommon
      stock equityCommon
      stock without par value, 500 million shares authorized, 261 million
      and 260 million
                shares
      issued and outstanding, respectively
              
              $
              6,071
              
              
              $
              6,028Unearned
      ESOP shares (1 million and 2 million shares, respectively)
              
              
              (25
              )
              
              
              (37
              )Accumulated
      other comprehensive loss
              
              
              (42
              )
              
              
              (34
              )Retained
      earnings
              
              
              2,514
              
              
              
              2,465Total
      common stock equity
              
              
              8,518
              
              
              
              8,422Preferred
      stock of subsidiaries – not subject to mandatory
redemption
              
              
              93
              
              
              
              93Minority
      interest
              
              
              6
              
              
              
              84Long-term
      debt, affiliate
              
              
              271
              
              
              
              271Long-term
      debt, net
              
              
              8,391
              
              
              
              8,466Total
      capitalization
              
              
              17,279
              
              
              
              17,336Current
      liabilitiesCurrent
      portion of long-term debt
              
              
              1,197
              
              
              
              877Short-term
      debt
              
              
              205
              
              
              
              201Accounts
      payable
              
              
              794
              
              
              
              819Interest
      accrued
              
              
              128
              
              
              
              173Dividends
      declared
              
              
              161
              
              
              
              160Customer
      deposits
              
              
              262
              
              
              
              255Regulatory
      liabilities
              
              
              145
              
              
              
              173Liabilities
      to be divested
              
              
              –
              
              
              
              8Income
      taxes accrued
              
              
              66
              
              
              
              8Other
      current liabilities
              
              
              428
              
              
              
              628Total
      current liabilities
              
              
              3,386
              
              
              
              3,302Deferred
      credits and other liabilitiesNoncurrent
      income tax liabilities
              
              
              288
              
              
              
              361Accumulated
      deferred investment tax credits
              
              
              136
              
              
              
              139Regulatory
      liabilities
              
              
              2,775
              
              
              
              2,554Asset
      retirement obligations
              
              
              1,397
              
              
              
              1,378Accrued
      pension and other benefits
              
              
              761
              
              
              
              763Capital
      lease obligations
              
              
              239
              
              
              
              239Other
      liabilities and deferred credits
              
              
              283
              
              
              
              293Total
      deferred credits and other liabilities
              
              
              5,879
              
              
              
              5,727Commitments
      and contingencies (Notes 12 and 13)Total
      capitalization and liabilities
              
              $
              26,544
              
              
              $
              26,365
 
 See
Notes to Progress Energy, Inc. UnauditedCondensedConsolidatedInterim Financial Statements.
  10
  PROGRESS
ENERGY, INC.
 UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of CASH
      FLOWS(in
      millions)Three
      months ended March 31
              
              2008
              
              
              2007Operating
      activitiesNet
      income
              
              $
              209
              
              
              $
              275Adjustments
      to reconcile net income to net cash provided by operating
      activitiesDepreciation
      and amortization
              
              
              235
              
              
              
              250Deferred
      income taxes and investment tax credits, net
              
              
              5
              
              
              
              120Deferred
      fuel cost
              
              
              24
              
              
              
              108Other
      adjustments to net income
              
              
              (47
              )
              
              
              (7
              )Cash
      provided (used) by changes in operating assets and
    liabilitiesReceivables
              
              
              390
              
              
              
              59Inventory
              
              
              4
              
              
              
              (34
              )Prepayments
      and other current assets
              
              
              14
              
              
              
              (64
              )Income
      taxes, net
              
              
              60
              
              
              
              (237
              )Accounts
      payable
              
              
              79
              
              
              
              (52
              )Other
      current liabilities
              
              
              (171
              )
              
              
              (4
              )Other
      assets and deferred debits
              
              
              (38
              )
              
              
              (83
              )Other
      liabilities and deferred credits
              
              
              13
              
              
              
              (15
              )Net
      cash provided by operating activities
              
              
              777
              
              
              
              316Investing
      activitiesGross
      property additions
              
              
              (618
              )
              
              
              (471
              )Nuclear
      fuel additions
              
              
              (41
              )
              
              
              (61
              )Proceeds
      from sales of discontinued operations and other assets, net of cash
      divested
              
              
              95
              
              
              
              30Purchases
      of available-for-sale securities and other investments
              
              
              (488
              )
              
              
              (192
              )Proceeds
      from sales of available-for-sale securities and other
      investments
              
              
              473
              
              
              
              252Other
      investing activities
              
              
              (6
              )
              
              
              –Net
      cash used by investing activities
              
              
              (585
              )
              
              
              (442
              )Financing
      activitiesIssuance
      of common stock
              
              
              20
              
              
              
              65Dividends
      paid on common stock
              
              
              (159
              )
              
              
              (155
              )Payments
      of short-term debt with original maturities greater than 90
      days
              
              
              (176
              )
              
              
              –Net
      increase in short-term debt
              
              
              180
              
              
              
              117Proceeds
      from issuance of long-term debt, net
              
              
              322
              
              
              
              –Retirement
      of long-term debt
              
              
              (80
              )
              
              
              –Cash
      distributions to minority interests of consolidated
      subsidiaries
              
              
              (85
              )
              
              
              –Other
      financing activities
              
              
              (69
              )
              
              
              (33
              )Net
      cash used by financing activities
              
              
              (47
              )
              
              
              (6
              )Net increase
      (decrease) in cash and cash equivalents
              
              
              145
              
              
              
              (132
              )Cash
      and cash equivalents at beginning of period
              
              
              255
              
              
              
              265Cash
      and cash equivalents at end of period
              
              $
              400
              
              
              $
              133Supplemental
      disclosuresSignificant
      noncash transactionsNote
      receivable for disposal of ownership interest in Ceredo
              
              $
              –
              
              
              $
              48Noncash
      property additions accrued for as of March 31
              
              
              276
              
              
              
              158See
      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, 2008
 
 UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of
      INCOME(in
      millions)Three
      months ended March 31
              
              2008
              
              
              2007Operating
      revenues
              
              $
              1,068
              
              
              $
              1,058Operating
      expensesFuel
      used in electric generation
              
              
              356
              
              
              
              351Purchased
      power
              
              
              49
              
              
              
              58Operation
      and maintenance
              
              
              248
              
              
              
              248Depreciation
      and amortization
              
              
              126
              
              
              
              117Taxes
      other than on income
              
              
              50
              
              
              
              50Other
              
              
              (1
              )
              
              
              (1
              )Total
      operating expenses
              
              
              828
              
              
              
              823Operating
      income
              
              
              240
              
              
              
              235Other
      incomeInterest
      income
              
              
              5
              
              
              
              6Other,
      net
              
              
              4
              
              
              
              3Total
      other income
              
              
              9
              
              
              
              9Interest
      chargesInterest
      charges
              
              
              58
              
              
              
              57Allowance
      for borrowed funds used during construction
              
              
              (2
              )
              
              
              (1
              )Total
      interest charges, net
              
              
              56
              
              
              
              56Income
      before income tax
              
              
              193
              
              
              
              188Income
      tax expense
              
              
              70
              
              
              
              64Net
      income
              
              
              123
              
              
              
              124Preferred
      stock dividend requirement
              
              
              1
              
              
              
              1Earnings
      for common stock
              
              $
              122
              
              
              $
              123
 
 See
Notes to PEC Unaudited Condensed Consolidated Interim Financial
Statements.
 12
  CAROLINA
POWER & LIGHT COMPANY
 d/b/a
PROGRESS ENERGY CAROLINAS, INC.
 UNAUDITED CONDENSEDCONSOLIDATED BALANCE
      SHEETS(in
      millions)
              
              March
      31, 2008
              
              
              December
      31, 2007ASSETSUtility
      plantUtility
      plant in service
              
              $
              15,176
              
              
              $
              15,117Accumulated
      depreciation
              
              
              (7,161
              )
              
              
              (7,097
              )Utility
      plant in service, net
              
              
              8,015
              
              
              
              8,020Held
      for future use
              
              
              2
              
              
              
              2Construction
      work in progress
              
              
              625
              
              
              
              566Nuclear
      fuel, net of amortization
              
              
              298
              
              
              
              292Total
      utility plant, net
              
              
              8,940
              
              
              
              8,880Current
      assetsCash
      and cash equivalents
              
              
              297
              
              
              
              25Short-term
      investments
              
              
              1
              
              
              
              1Receivables,
      net
              
              
              451
              
              
              
              491Receivables
      from affiliated companies
              
              
              29
              
              
              
              42Notes
      receivable from affiliated companies
              
              
              85
              
              
              
              –Inventory
              
              
              507
              
              
              
              510Deferred
      fuel cost
              
              
              133
              
              
              
              148Prepayments
      and other current assets
              
              
              32
              
              
              
              49Total
      current assets
              
              
              1,535
              
              
              
              1,266Deferred
      debits and other assetsRegulatory
      assets
              
              
              653
              
              
              
              680Nuclear
      decommissioning trust funds
              
              
              771
              
              
              
              804Miscellaneous
      other property and investments
              
              
              197
              
              
              
              192Other
      assets and deferred debits
              
              
              191
              
              
              
              160Total
      deferred debits and other assets
              
              
              1,812
              
              
              
              1,836Total
      assets
              
              $
              12,287
              
              
              $
              11,982CAPITALIZATION
      AND LIABILITIESCommon
      stock equityCommon
      stock without par value, 200 million shares authorized, 160 million shares
      issued and outstanding
              
              $
              2,072
              
              
              $
              2,054Unearned
      ESOP common stock
              
              
              (25
              )
              
              
              (37
              )Accumulated
      other comprehensive loss
              
              
              (15
              )
              
              
              (10
              )Retained
      earnings
              
              
              1,894
              
              
              
              1,772Total
      common stock equity
              
              
              3,926
              
              
              
              3,779Preferred
      stock – not subject to mandatory redemption
              
              
              59
              
              
              
              59Long-term
      debt, net
              
              
              3,107
              
              
              
              3,183Total
      capitalization
              
              
              7,092
              
              
              
              7,021Current
      liabilitiesCurrent
      portion of long-term debt
              
              
              700
              
              
              
              300Notes
      payable to affiliated companies
              
              
              –
              
              
              
              154Accounts
      payable
              
              
              287
              
              
              
              308Payables
      to affiliated companies
              
              
              58
              
              
              
              71Interest
      accrued
              
              
              51
              
              
              
              58Customer
      deposits
              
              
              73
              
              
              
              70Income
      taxes accrued
              
              
              69
              
              
              
              27Other
      current liabilities
              
              
              153
              
              
              
              182Total
      current liabilities
              
              
              1,391
              
              
              
              1,170Deferred
      credits and other liabilitiesNoncurrent
      income tax liabilities
              
              
              936
              
              
              
              936Accumulated
      deferred investment tax credits
              
              
              120
              
              
              
              122Regulatory
      liabilities
              
              
              1,106
              
              
              
              1,098Asset
      retirement obligations
              
              
              1,078
              
              
              
              1,063Accrued
      pension and other benefits
              
              
              457
              
              
              
              459Other
      liabilities and deferred credits
              
              
              107
              
              
              
              113Total
      deferred credits and other liabilities
              
              
              3,804
              
              
              
              3,791Commitments
      and contingencies (Notes 12 and 13)Total
      capitalization and liabilities
              
              $
              12,287
              
              
              $
              11,982
 
 See
Notes to PEC Unaudited Condensed Consolidated Interim Financial
Statements.
  13
  CAROLINA
POWER & LIGHT COMPANY
 d/b/a
PROGRESS ENERGY CAROLINAS, INC.
 UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of CASH
      FLOWS(in
      millions)Three
      months ended March 31
              
              2008
              
              
              2007Operating
      activitiesNet
      income
              
              $
              123
              
              
              $
              124Adjustments
      to reconcile net income to net cash provided by operating
      activitiesDepreciation
      and amortization
              
              
              151
              
              
              
              138Deferred
      income taxes and investment tax credits, net
              
              
              6
              
              
              
              7Deferred
      fuel cost
              
              
              42
              
              
              
              44Other
      adjustments to net income
              
              
              13
              
              
              
              (11
              )Cash
      provided (used) by changes in operating assets and
    liabilitiesReceivables
              
              
              38
              
              
              
              25Receivables
      from affiliated companies
              
              
              13
              
              
              
              7Inventory
              
              
              8
              
              
              
              (8
              )Prepayments
      and other current assets
              
              
              17
              
              
              
              3Income
      taxes, net
              
              
              50
              
              
              
              (3
              )Accounts
      payable
              
              
              22
              
              
              
              (17
              )Payables
      to affiliated companies
              
              
              (13
              )
              
              
              (66
              )Other
      current liabilities
              
              
              (28
              )
              
              
              (25
              )Other
      assets and deferred debits
              
              
              (19
              )
              
              
              (8
              )Other
      liabilities and deferred credits
              
              
              (4
              )
              
              
              –Net
      cash provided by operating activities
              
              
              419
              
              
              
              210Investing
      activitiesGross
      property additions
              
              
              (173
              )
              
              
              (208
              )Nuclear
      fuel additions
              
              
              (41
              )
              
              
              (38
              )Purchases
      of available-for-sale securities and other investments
              
              
              (193
              )
              
              
              (120
              )Proceeds
      from sales of available-for-sale securities and other
      investments
              
              
              185
              
              
              
              162Changes
      in advances to affiliated companies
              
              
              (85
              )
              
              
              24Other
      investing activities
              
              
              (4
              )
              
              
              6Net
      cash used by investing activities
              
              
              (311
              )
              
              
              (174
              )Financing
      activitiesDividends
      paid on preferred stock
              
              
              (1
              )
              
              
              (1
              )Dividends
      paid to parent
              
              
              –
              
              
              
              (36
              )Proceeds
      from issuance of long-term debt, net
              
              
              322
              
              
              
              –Changes
      in advances from affiliated companies
              
              
              (154
              )
              
              
              –Other
      financing activities
              
              
              (3
              )
              
              
              11Net
      cash provided (used) by financing activities
              
              
              164
              
              
              
              (26
              )Net
      increase in cash and cash equivalents
              
              
              272
              
              
              
              10Cash
      and cash equivalents at beginning of period
              
              
              25
              
              
              
              71Cash
      and cash equivalents at end of period
              
              $
              297
              
              
              $
              81Supplemental
      disclosuresSignificant
      noncash transactionsNoncash
      property additions accrued for as of March 31
              
              $
              76
              
              
              $
              83See
      Notes to PEC Unaudited Condensed Consolidated Interim Financial
      Statements.
 
  14
  FLORIDA
POWER CORPORATION
 d/b/a
PROGRESS ENERGY FLORIDA, INC.
 UNAUDITED
CONDENSED INTERIM FINANCIAL STATEMENTS
 March
31, 2008
 
 UNAUDITED CONDENSED STATEMENTS of
INCOME(in
      millions)Three
      months ended March 31
              
              2008
              
              
              2007Operating
      revenues
              
              $
              996
              
              
              $
              1,011Operating
      expensesFuel
      used in electric generation
              
              
              341
              
              
              
              385Purchased
      power
              
              
              183
              
              
              
              163Operation
      and maintenance
              
              
              203
              
              
              
              175Depreciation
      and amortization
              
              
              76
              
              
              
              97Taxes
      other than on income
              
              
              71
              
              
              
              74Total
      operating expenses
              
              
              874
              
              
              
              894Operating
      income
              
              
              122
              
              
              
              117Other
      incomeInterest
      income
              
              
              1
              
              
              
              1Other,
      net
              
              
              17
              
              
              
              7Total
      other income
              
              
              18
              
              
              
              8Interest
      chargesInterest
      charges
              
              
              50
              
              
              
              39Allowance
      for borrowed funds used during construction
              
              
              (6
              )
              
              
              (2
              )Total
      interest charges, net
              
              
              44
              
              
              
              37Income
      before income tax
              
              
              96
              
              
              
              88Income
      tax expense
              
              
              29
              
              
              
              27Net
      income
              
              
              67
              
              
              
              61Preferred
      stock dividend requirement
              
              
              1
              
              
              
              1Earnings
      for common stock
              
              $
              66
              
              
              $
              60
  See
Notes to PEF Unaudited Condensed Interim Financial Statements.
  15
  FLORIDA
POWER CORPORATION
 d/b/a
PROGRESS ENERGY FLORIDA, INC.
 UNAUDITED CONDENSED BALANCE SHEETS(in
      millions)
              
              March
      31, 2008
              
              
              December
      31, 2007ASSETSUtility
      plantUtility
      plant in service
              
              $
              10,129
              
              
              $
              10,025Accumulated
      depreciation
              
              
              (3,816
              )
              
              
              (3,738
              )Utility
      plant in service, net
              
              
              6,313
              
              
              
              6,287Held
      for future use
              
              
              35
              
              
              
              35Construction
      work in progress
              
              
              1,499
              
              
              
              1,199Nuclear
      fuel, net of amortization
              
              
              74
              
              
              
              79Total
      utility plant, net
              
              
              7,921
              
              
              
              7,600Current
      assetsCash
      and cash equivalents
              
              
              16
              
              
              
              23Receivables,
      net
              
              
              307
              
              
              
              351Receivables
      from affiliated companies
              
              
              15
              
              
              
              8Notes
      receivable from affiliated companies
              
              
              –
              
              
              
              149Inventory
              
              
              493
              
              
              
              484Deferred
      income taxes
              
              
              –
              
              
              
              39Income
      taxes receivable
              
              
              –
              
              
              
              41Derivative
      assets
              
              
              204
              
              
              
              83Prepayments
      and other current assets
              
              
              11
              
              
              
              9Total
      current assets
              
              
              1,046
              
              
              
              1,187Deferred
      debits and other assetsRegulatory
      assets
              
              
              273
              
              
              
              266Nuclear
      decommissioning trust funds
              
              
              542
              
              
              
              580Miscellaneous
      other property and investments
              
              
              44
              
              
              
              46Derivative
      assets
              
              
              174
              
              
              
              100Prepaid
      pension cost
              
              
              227
              
              
              
              221Other
      assets and deferred debits
              
              
              80
              
              
              
              63Total
      deferred debits and other assets
              
              
              1,340
              
              
              
              1,276Total
      assets
              
              $
              10,307
              
              
              $
              10,063CAPITALIZATION
      AND LIABILITIESCommon
      stock equityCommon
      stock without par value, 60 million shares authorized, 100 shares issued
      and outstanding
              
              $
              1,110
              
              
              $
              1,109Accumulated
      other comprehensive loss
              
              
              (12
              )
              
              
              (8
              )Retained
      earnings
              
              
              1,967
              
              
              
              1,901Total
      common stock equity
              
              
              3,065
              
              
              
              3,002Preferred
      stock – not subject to mandatory redemption
              
              
              34
              
              
              
              34Long-term
      debt, net
              
              
              2,687
              
              
              
              2,686Total
      capitalization
              
              
              5,786
              
              
              
              5,722Current
      liabilitiesCurrent
      portion of long-term debt
              
              
              452
              
              
              
              532Notes
      payable to affiliated companies
              
              
              95
              
              
              
              –Accounts
      payable
              
              
              485
              
              
              
              473Payables
      to affiliated companies
              
              
              54
              
              
              
              87Interest
      accrued
              
              
              35
              
              
              
              57Customer
      deposits
              
              
              189
              
              
              
              185Derivative
      liabilities
              
              
              11
              
              
              
              38Regulatory
      liabilities
              
              
              145
              
              
              
              173Other
      current liabilities
              
              
              189
              
              
              
              92Total
      current liabilities
              
              
              1,655
              
              
              
              1,637Deferred
      credits and other liabilitiesNoncurrent
      income tax liabilities
              
              
              354
              
              
              
              401Accumulated
      deferred investment tax credits
              
              
              16
              
              
              
              17Regulatory
      liabilities
              
              
              1,544
              
              
              
              1,330Asset
      retirement obligations
              
              
              319
              
              
              
              315Accrued
      pension and other benefits
              
              
              304
              
              
              
              304Capital
      lease obligations
              
              
              223
              
              
              
              224Other
      liabilities and deferred credits
              
              
              106
              
              
              
              113Total
      deferred credits and other liabilities
              
              
              2,866
              
              
              
              2,704Commitments
      and contingencies (Notes 12 and 13)Total
      capitalization and liabilities
              
              $
              10,307
              
              
              $
              10,063
 
 See
Notes to PEF 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
              
              2008
              
              
              2007Operating
      activitiesNet
      income
              
              $
              67
              
              
              $
              61Adjustments
      to reconcile net income to net cash provided by operating
      activitiesDepreciation
      and amortization
              
              
              80
              
              
              
              103Deferred
      income taxes and investment tax credits, net
              
              
              15
              
              
              
              14Deferred
      fuel (credit) cost
              
              
              (18
              )
              
              
              64Other
      adjustments to net income
              
              
              (13
              )
              
              
              –Cash
      provided (used) by changes in operating assets and
    liabilitiesReceivables
              
              
              40
              
              
              
              41Receivables
      from affiliated companies
              
              
              (7
              )
              
              
              2Inventory
              
              
              (8
              )
              
              
              (23
              )Prepayments
      and other current assets
              
              
              (3
              )
              
              
              56Income
      taxes, net
              
              
              43
              
              
              
              36Accounts
      payable
              
              
              70
              
              
              
              18Payables
      to affiliated companies
              
              
              (33
              )
              
              
              (71
              )Other
      current liabilities
              
              
              35
              
              
              
              12Other
      assets and deferred debits
              
              
              (17
              )
              
              
              6Other
      liabilities and deferred credits
              
              
              19
              
              
              
              (10
              )Net
      cash provided by operating activities
              
              
              270
              
              
              
              309Investing
      activitiesGross
      property additions
              
              
              (446
              )
              
              
              (261
              )Nuclear
      fuel additions
              
              
              –
              
              
              
              (23
              )Purchases
      of available-for-sale securities and other investments
              
              
              (247
              )
              
              
              (44
              )Proceeds
      from sales of available-for-sale securities and other
      investments
              
              
              247
              
              
              
              44Changes
      in advances to affiliated companies
              
              
              149
              
              
              
              –Proceeds
      from sales of assets to affiliated companies
              
              
              8
              
              
              
              –Other
      investing activities
              
              
              (2
              )
              
              
              –Net
      cash used by investing activities
              
              
              (291
              )
              
              
              (284
              )Financing
      activitiesDividends
      paid on preferred stock
              
              
              (1
              )
              
              
              (1
              )Retirement
      of long-term debt
              
              
              (80
              )
              
              
              –Changes
      in advances from affiliated companies
              
              
              95
              
              
              
              (36
              )Other
      financing activities
              
              
              –
              
              
              
              1Net
      cash provided (used) by financing activities
              
              
              14
              
              
              
              (36
              )Net
      decrease in cash and cash equivalents
              
              
              (7
              )
              
              
              (11
              )Cash
      and cash equivalents at beginning of period
              
              
              23
              
              
              
              23Cash
      and cash equivalents at end of period
              
              $
              16
              
              
              $
              12Supplemental
      disclosuresSignificant
      noncash transactionsNoncash
      property additions accrued for as of March 31
              
              $
              198
              
              
              $
              75See
      Notes to PEF 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 through 9, and 11 through 13PEF
              1,
      2, 4 through 9, and 11 through
13
  18
  PROGRESS
ENERGY, INC.
 CAROLINA
POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC.
 FLORIDA
POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA, INC.
 COMBINED
NOTES TO UNAUDITED CONDENSED INTERIM FINANCIAL STATEMENTS
 
 In this
report, Progress Energy, which includes Progress Energy, Inc. holding company
(the Parent) and its regulated and nonregulated subsidiaries on a consolidated
basis, is at times referred to as “we,” “us” or “our.” When discussing Progress
Energy’s financial information, it necessarily includes the results of Carolina
Power & Light Company d/b/a Progress Energy Carolinas, Inc. (PEC) and
Florida Power Corporation d/b/a Progress Energy Florida, Inc. (PEF)
(collectively, the Utilities). The term “Progress Registrants” refers to each of
the three separate registrants: Progress Energy, PEC and PEF. The information in
these combined notes relates to each of the Progress Registrants as noted in the
Index to the Combined Notes. However, neither of the Utilities makes any
representation as to information related solely to Progress Energy or the
subsidiaries of Progress Energy other than itself.
  1.
              ORGANIZATION AND
      SUMMARY OF SIGNIFICANT ACCOUNTING
  POLICIES
  A.   ORGANIZATION
  PROGRESS
ENERGY, INC.
 
 The
Parent is a holding company headquartered in Raleigh, N.C. As such, we are
subject to regulation by the Federal Energy Regulatory Commission (FERC) under
the regulatory provisions of the Public Utility Holding Company Act of 2005
(PUHCA 2005).
  Our
reportable segments are PEC and PEF, both of which are primarily engaged in the
generation, transmission, distribution and sale of electricity. The Corporate
and Other segment primarily includes amounts applicable to the activities of the
Parent and Progress Energy Service Company, LLC (PESC) and other miscellaneous
nonregulated businesses that do not separately meet the quantitative disclosure
requirements as a separate business segment. See Note 10 for further information
about our segments.
  PEC
 
 PEC is a
regulated public utility primarily engaged in the generation, transmission,
distribution and sale of electricity in portions of North Carolina and South
Carolina. PEC’s subsidiaries are involved in insignificant nonregulated business
activities. PEC is subject to the regulatory provisions of the North Carolina
Utilities Commission (NCUC), Public Service Commission of South Carolina
(SCPSC), the United States Nuclear Regulatory Commission (NRC) and the
FERC.
 
 PEF
 
 PEF is a
regulated public utility primarily engaged in the generation, transmission,
distribution and sale of electricity in west central Florida. PEF is subject to
the regulatory provisions of the Florida Public Service Commission (FPSC), the
NRC and the FERC.
  B.  
BASIS OF PRESENTATION
  These
financial statements have been prepared in accordance with accounting principles
generally accepted in the United States of America (GAAP) for interim financial
information and with the instructions to Form 10-Q and Regulation S-X.
Accordingly, they do not include all of the information and footnotes required
by GAAP for annual financial statements. The December 31, 2007 condensed balance
sheet data was derived from audited financial statements but does not include
all disclosures required by GAAP. Because the accompanying interim financial
statements do not include all of the information and footnotes required by GAAP
for annual financial statements, they should be read in conjunction with the
audited financial statements and notes thereto included in the Progress
Registrants’ annual report on Form 10-K for the fiscal year ended December 31,
2007 (2007 Form 10-K).
  In accordance with
the provisions of Accounting Principles BoardOpinion No. 28, “Interim
Financial Reporting,” GAAP requires companies to apply a levelized effective tax
rate to interim periods that is consistent with the
  19
 estimated
annual effective tax rate. The tax levelization expense or benefit recorded
during the interim period, which will have no impact on total year net income,
maintains an effective tax rate consistent with the estimated annual effective
tax rate. The fluctuations in the effective tax rate for the three months ended
March 31, 2008, are primarily due to seasonal fluctuations in energy sales and
earnings from the Utilities. The fluctuations in the effective tax rate for the
three months ended March 31, 2007, are primarily due to the recognition of
synthetic fuels tax credits and seasonal fluctuations in energy sales and
earnings from the Utilities. Total tax levelization adjustments increased
(decreased) income tax expense for the Progress Registrants for the three months
ended March 31, 2008 and 2007, as follows:
 Three
      Months Ended March 31,(in
      millions)
              
              2008
              
              
              2007Progress
      Energy
              
              $
              (1
              )
              
              $
              (8
              )PEC
              
              
              (3
              )
              
              
              (1
              )PEF
              
              
              1
              
              
              
              –
 
 For the
three months ended March 31, 2007, $10 million of the net $8 million tax
levelization benefit was related to synthetic fuels tax credits recorded by the
synthetic fuels businesses and is included in discontinued operations on the
Consolidated Statements of Income, pursuant to the intraperiod tax allocation
rules as set forth in Statement of Financial Accounting Standard (SFAS) No. 109,
“Accounting for Income Taxes” (SFAS No. 109). When the synthetic fuels
businesses were reclassified to discontinued operations in the fourth quarter of
2007 (See Note 3A), the impacts of the quarterly tax levelization adjustments
associated with the synthetic fuels tax credits were not also reclassified to
discontinued operations, including the $10 million levelization benefit for the
three months ended March 31, 2007 discussed above. Consequently, the
presentation of the unaudited summarized quarterly financial data previously
reported for Progress Energy in Note 24 in the 2007 Form 10-K was not correct.
As a result, the unaudited summarized quarterly financial data has been
restated. This correction does not affect our Consolidated Statements of Income
for 2007 or 2006, as the quarterly tax levelization adjustments net to zero on
an annual basis. The following table presents specific line item amounts for the
three months ended March 31, 2007, included in Note 24 in the 2007 Form 10-K
that have been restated as a result of this correction:
  Progress
      Energy(in
      millions except per share data)
                
                As
      originally reported
                
                
                As
      restatedIncome
      from continuing operations
                
                $
                159
                
                
                $
                149Common
      stock dataBasic
      earnings per common shareIncome
      from continuing operations
                
                
                0.63
                
                
                
                0.59Diluted
      earnings per common shareIncome
      from continuing operations
                
                
                0.62
                
                
                
                0.59
  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)
              
              2008
              
              
              2007Progress
      Energy
              
              $
              65
              
              
              $
              66PEC
              
              
              25
              
              
              
              24PEF
              
              
              40
              
              
              
              42
 
 The
amounts included in these financial statements are unaudited but, in the opinion
of management, reflect all adjustments necessary to fairly present the Progress
Registrants’ financial position and results of operations for the interim
periods. Unless otherwise noted, all adjustments are normal and recurring in
nature. Due to seasonal weather variations and the timing of outages of electric
generating units, especially nuclear-fueled units, the results of operations for
interim periods are not necessarily indicative of amounts expected for the
entire year or future periods.
  20
  In
preparing financial statements that conform to GAAP, management must make
estimates and assumptions that affect the reported amounts of assets and
liabilities, the reported amounts of revenues and expenses and the disclosure of
contingent assets and liabilities at the date of the financial statements.
Actual results could differ from those estimates.
  Certain
amounts for 2007 have been reclassified to conform to the 2008
presentation.
  C. 
CONSOLIDATION OF VARIABLE INTEREST ENTITIES
  We
consolidate all voting interest entities in which we own a majority voting
interest and all variable interest entities for which we are the primary
beneficiary in accordance with Financial Accounting Standards Board (FASB)
Interpretation No. 46R, “Consolidation of Variable Interest Entities – an
Interpretation of ARB No. 51” (FIN 46R).
  PROGRESS
ENERGY
  In March
2007, we disposed of our 100 percent ownership interest in Ceredo Synfuel LLC
(Ceredo), a coal-based solid synthetic fuels production facility that qualifies
for federal tax credits under Section 45K of the Internal Revenue Code (the
Code), to a third-party buyer. Progress Energy, through its subsidiary Progress
Fuels Corporation (Progress Fuels), is the primary beneficiary of, and continues
to consolidate Ceredo. See Note 3F for additional information on the disposal of
Ceredo.
  In
addition to the variable interests listed below for PEC and PEF, we have
interests through other subsidiaries in several variable interest entities for
which we are not the primary beneficiary. These arrangements include investments
in five limited liability partnerships and limited liability corporations. At
March 31, 2008, the aggregate additional maximum loss exposure that we could be
required to record in our income statement as a result of these arrangements was
$6 million, which represents our net remaining investment in the entities. The
creditors of these variable interest entities do not have recourse to our
general credit in excess of the aggregate maximum loss exposure.
  PEC
  PEC is
the primary beneficiary of, and consolidates, two limited partnerships that
qualify for federal affordable housing and historic tax credits under Section 42
of the Code. At March 31, 2008, the assets of the two entities totaled $37
million, the majority of which are collateral for the entities’ obligations, and
were included in miscellaneous other property and investments in the
Consolidated Balance Sheets.
  PEC has
an interest in and consolidates one limited partnership that invests in 17
low-income housing partnerships that qualify for federal and state tax credits.
PEC also has an interest in one power plant resulting from long-term power
purchase contracts. PEC has requested the necessary information to determine if
the 17 partnerships and the power plant owner are variable interest entities or
to identify the primary beneficiaries; all entities from which the necessary
financial information was requested declined to provide the information to PEC
and accordingly, PEC has applied the information scope exception in FIN 46R,
paragraph 4(g), to the 17 partnerships and the power plant. PEC believes that if
it is determined to be the primary beneficiary of these entities, the effect of
consolidating the entities would result in increases to total assets, long-term
debt and other liabilities, but would have an insignificant or no impact on
PEC’s common stock equity, net earnings or cash flows. However, because PEC has
not received any financial information from the counterparties, the impact
cannot be determined at this time.
  PEC also
has interests in several other variable interest entities for which PEC is not
the primary beneficiary. These arrangements include investments in 21 limited
liability partnerships, limited liability corporations and venture capital funds
and two building leases with special-purpose entities. At March 31, 2008, the
aggregate maximum loss exposure that PEC could be required to record on its
income statement as a result of these arrangements was $18 million, which
primarily represents its net remaining investment in these entities. The
creditors of these variable interest entities do not have recourse to the
general credit of PEC in excess of the aggregate maximum loss
exposure.
  21
  PEF
  PEF has
interests in four variable interest entities for which PEF is not the primary
beneficiary. These arrangements include investments in one venture capital fund,
one limited liability corporation, one building lease with a special-purpose
entity and one operating lease with a special-purpose entity. At March 31, 2008,
the aggregate maximum loss exposure that PEF could be required to record in its
income statement as a result of these arrangements was $56 million. The majority
of this exposure is related to a prepayment clause in the building lease of
which $2 million had been prepaid at March 31, 2008. The creditors of these
variable interest entities do not have recourse to the general credit of PEF in
excess of the aggregate maximum loss exposure.
  2.
              NEW ACCOUNTING
      STANDARDS
  Fair
Value Measurements - Adoption of FASB Statements Nos. 157 and 159
  Refer to
Note 7 for information regarding our first quarter 2008 implementation of FASB
Statement of Financial Accounting Standards SFAS No. 157, “Fair Value
Measurements” (SFAS No. 157).
  In
February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for
Financial Assets and Financial Liabilities – Including an Amendment of FASB
Statement No. 115” (SFAS No. 159), which permits entities to choose to measure
many financial instruments and certain other items at fair value that are not
currently required to be measured at fair value. The decision about whether to
elect the fair value option is applied on an instrument by instrument basis, is
irrevocable (unless a new election date occurs) and is applied to the entire
financial instrument. SFAS No. 159 was effective for us and the Utilities on
January 1, 2008. We and the utilities did not elect to adopt the fair value
option for any financial instruments.
  FASB
Staff Position No. 39-1, An Amendment of FIN 39, Offsetting of Amounts Related
to Certain Contracts
  FASB
Interpretation No. 39, “Offsetting of Amounts Related to Certain Contracts” (FIN
39), specifies what conditions must be met for an entity to have the right to
offset assets and liabilities in the balance sheet and clarifies when it is
appropriate to offset amounts recognized for forward, interest rate swap,
currency swap, option, and other conditional or exchange contracts. FIN 39 also
permits offsetting of fair value amounts recognized for multiple contracts
executed with the same counterparty under a master netting arrangement. On April
30, 2007, the FASB issued FASB Staff Position (FSP) No. FIN 39-1, “An Amendment
of FIN 39, Offsetting of Amounts Related to Certain Contracts” (FSP FIN 39-1),
which amended portions of FIN 39 to make certain terms consistent with those
used in SFAS No. 133, “Accounting for Derivative Instruments and Hedging
Activities” (SFAS No. 133). FSP FIN 39-1 also amends FIN 39 to allow for the
offsetting of fair value amounts for the right to reclaim collateral assets or
liabilities arising from the same master netting arrangement as the derivative
instruments. We implemented the FSP as of January 1, 2008, as a retrospective
change in accounting principle for all financial statements presented. We and
the Utilities previously offset fair value amounts recognized for derivative
instruments under master netting arrangements. As allowed under FSP FIN 39-1, we
and the Utilities changed our accounting policy effective January 1, 2008, and
discontinued the offset of fair value amounts for such derivatives. The change
had no impact on our or the Utilities’ results of operations or equity and
resulted in increases in previously-reported December 31, 2007 assets and
liabilities, as follows:
 (in
      millions)
              
              Progress
      Energy
              
              
              PEC
              
              
              PEFCurrent
      assets
              
              $
              54
              
              
              $
              19
              
              
              $
              35Noncurrent
      assets
              
              
              25
              
              
              
              1
              
              
              
              24Current
      liabilities
              
              
              54
              
              
              
              19
              
              
              
              35Noncurrent
      liabilities
              
              
              25
              
              
              
              1
              
              
              
              24
 
 FASB
Statement No. 161, Disclosures About Derivative Instruments and Hedging
Activities — an amendment of FASB Statement No. 133
  In March
2008, the FASB issued SFAS No. 161, “Disclosures About Derivative Instruments
and Hedging Activities — an amendment of FASB Statement No. 133” (SFAS No. 161),
which requires entities to provide enhanced
  22
  disclosures
about how and why an entity uses derivative instruments, how derivative
instruments and related hedged items are accounted for under SFAS No. 133, and
how derivative instruments and related hedged items affect an entity’s financial
position, financial performance, and cash flows. SFAS No. 161 requires
significant quantitative disclosures to be presented in a tabular format,
including disclosures of the location, by line item, of fair value amounts of
derivative instruments in the balance sheet and the location, by line item, of
amounts of derivative gains and losses reported in the income statement. SFAS
No. 161 also requires entities to disclose information regarding the existence
and nature of credit-risk-related contingent features included in derivative
instruments that require the instrument to be settled or collateral posted in
the event of a credit downgrade. SFAS No. 161 is effective for us and the
Utilities on January 1, 2009. The adoption of SFAS No. 161 will change certain
disclosures in the notes to the financial statments, but will have no impact on
our or the Utilities' financial position or results of operations.
 
 3.
              DIVESTITURES
  A.
              TERMINALS
      OPERATIONS AND SYNTHETIC FUELS
BUSINESSES
  On March
7, 2008, we sold coal terminals and docks in West Virginia and Kentucky
(Terminals) for $71 million in gross cash proceeds. The terminals have 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. As a result, 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 have been restated for all
periods presented to reflect the operations of Terminals as discontinued
operations.
  Prior to
2008, we had substantial operations associated with the production of coal-based
solid synthetic fuels as defined under Section 29 (Section 29) of the Internal
Revenue Code (the Code). The production and sale of these products qualified for
federal income tax credits so long as certain requirements were satisfied.
Synthetic fuels were generally not economical to produce and sell absent the
credits. On September 14, 2007, we idled production of synthetic fuels at our
majority-owned synthetic fuels facilities due to the high level of oil prices.
On October 12, 2007, based upon the continued high level of oil prices,
unfavorable oil price projections through the end of 2007, and the expiration of
the synthetic fuels tax credit program at the end of 2007, we permanently ceased
production of synthetic fuels at our majority-owned facilities. 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. In accordance
with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived
Assets” (SFAS No. 144), operations must be abandoned prior to reporting them as
discontinued operations. The accompanying consolidated income statements have
been restated for all periods presented to reflect the abandoned operations of
our synthetic fuels businesses as discontinued operations.
 
 In
addition, as discussed in Note 1B, the recognition of tax credits generated by
the production and sale of synthetic fuels historically resulted in significant
fluctuations in our effective tax rate for interim periods. Pursuant to the
intraperiod tax allocation rules of SFAS No. 109, $10 million of tax
levelization benefit, which is primarily related to the recognition of synthetic
fuels tax credits, is included in the discontinued operations income tax benefit
for the three months ended March 31, 2007.
 
 Results
of discontinued operations for the three months ended March 31 for Terminals and
the synthetic fuels businesses were as follows:
 (in
      millions)
              
              2008
              
              
              2007Revenues
              
              $
              17
              
              
              $
              262Earnings
      before income taxes and minority interest
              
              
              10
              
              
              
              15Income
      tax benefit
              
              
              3
              
              
              
              53Minority
      interest portion of synthetic fuel (earnings) losses
              
              
              (1
              )
              
              
              3Net
      earnings from discontinued operations
              
              
              12
              
              
              
              71Gain
      on disposal of discontinued operations, including income tax expense of
      $7
              
              
              46
              
              
              
              –Earnings
      from discontinued operations
              
              $
              58
              
              
              $
              71
  23
  B.
              CCO
      – GEORGIA OPERATIONS
  On March
9, 2007, our subsidiary, Progress Ventures, Inc. (PVI), entered into a series of
transactions to sell or assign substantially all of its Competitive Commercial
Operations (CCO) physical and commercial assets and liabilities. Assets divested
include approximately 1,900 megawatts (MW) of gas-fired generation assets in
Georgia. The sale of the generation assets closed on June 11, 2007, for a net
sales price of $615 million. We recorded an estimated loss of $226 million in
December 2006. Based on the terms of the final agreement, during the quarter
ended March 31, 2007, we reversed $16 million after-tax of the impairment
recorded in 2006.
  Additionally,
on June 1, 2007, PVI closed the transaction involving the assignment of a
contract portfolio consisting of full-requirements contracts with 16 Georgia
electric membership cooperatives (the Georgia Contracts), forward gas and power
contracts, gas transportation, structured power and other contracts to a third
party. This represents substantially all of our nonregulated energy marketing
and trading operations. As a result of the assignments, PVI made a net cash
payment of $347 million, which represents the net cost to assign the Georgia
Contracts and other related contracts. In the quarter ended June 30, 2007, we
recorded a charge associated with the costs to exit the Georgia Contracts, and
other related contracts, of $349 million after-tax. We used the net proceeds
from these transactions for general corporate purposes.
  The
accompanying consolidated financial statements reflect the operations of CCO as
discontinued operations. Interest expense has been allocated to discontinued
operations based on their respective net assets, assuming a uniform
debt-to-equity ratio across our operations. Pre-tax interest expense allocated
for the three months ended March 31, 2007, was $8 million. We ceased recording
depreciation upon classification of the assets as discontinued operations in
December 2006. Results of CCO discontinued operations for the three months ended
March 31 were as follows:
 (in
      millions)
              
              2007Revenues
              
              $
              252Earnings
      before income taxes
              
              
              70Income
      tax expense
              
              
              (27
              )Net
      earnings from discontinued operations
              
              
              43Reversal
      of estimated loss on disposal of discontinued operations, including income
      tax benefit of $2
              
              
              16Earnings
      from discontinued operations
              
              $
              59
 
 C.
              COAL
      MINING BUSINESSES
  On March
7, 2008, we sold the remaining operations of Progress Fuels subsidiaries engaged
in the coal mining business (Coal Mining) for gross cash proceeds of $23
million. These assets include Powell Mountain Coal Co. and Dulcimer Land Co.,
which consist of approximately 30,000 acres in Lee County, Va. and Harlan
County, Ky. The property contains an estimated 40 million tons of high quality
coal reserves. 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. We ceased recording depreciation expense upon
classification of Coal Mining as discontinued operations in November 2005.
Results of Coal Mining discontinued operations for the three months ended March
31 were as follows:
 (in
      millions)
              
              2008
              
              
              2007Revenues
              
              $
              2
              
              
              $
              7Loss
      before income taxes
              
              
              (7
              )
              
              
              (6
              )Income
      tax benefit
              
              
              1
              
              
              
              2Net
      loss from discontinued operations
              
              
              (6
              )
              
              
              (4
              )Gain
      on disposal of discontinued operations, including income tax expense of
      $2
              
              
              7
              
              
              
              –Earnings
      (loss) from discontinued operations
              
              $
              1
              
              
              $
              (4
              )
  24
  D.
              OTHER
      DIVERSIFIED BUSINESSES
  On
October 2, 2006, we sold our natural gas drilling and production business (Gas)
to EXCO Resources, Inc. for approximately $1.1 billion in net proceeds. Based on
the net proceeds associated with the sale, we recorded an after-tax net gain on
disposal of $300 million during the year ended December 31, 2006. We recorded an
after-tax loss of $1 million (net of $1 million tax benefit) during the three
months ended March 31, 2007, primarily related to working capital adjustments.
The accompanying consolidated financial statements reflect the operations of Gas
as discontinued operations.
  On March
24, 2005, we completed the sale of Progress Rail Services Corporation (Progress
Rail) to One Equity Partners LLC, a private equity firm unit of J.P. Morgan
Chase & Co. During the three months ended March 31, 2008, we recorded an
after-tax gain on disposal of $1 million in connection with a reduction of
guarantees and indemnifications provided by Progress Fuels and Progress Energy
for certain legal, tax and environmental matters to One Equity Partners, LLC
(See Note 13B). The ultimate resolution of these matters could result
in adjustments to the loss on disposal in future periods. The accompanying
consolidated financial statements reflect the operations of Progress Rail as
discontinued operations.
  Also
included in discontinued operations are earnings from other fuels businesses of
$1 million, net of tax, for the three months ended March 31, 2007.
  E.
              NET
      ASSETS OF DISCONTINUED OPERATIONS
  At
December 31, 2007, the assets and liabilities of Terminals and the remaining
assets and liabilities of Coal Mining operations were included in net assets to
be divested. The major balance sheet classes included in assets and liabilities
to be divested in the Consolidated Balance Sheets were as follows:
 
 (in
      millions)
              
              December
      31, 2007Inventory
              
              $
              6Other
      current assets
              
              
              2Total
      property, plant and equipment, net
              
              
              38Total
      other assets
              
              
              6Assets
      to be divested
              
              $
              52Accrued
      expenses
              
              $
              3Long-term
      liabilities
              
              
              5Liabilities
      to be divested
              
              $
              8
 
 F.
              CEREDO
      SYNTHETIC FUELS INTERESTS
  On March
30, 2007, our Progress Fuels subsidiary disposed of its 100 percent ownership
interest in Ceredo, a subsidiary that produced and sold qualifying coal-based
solid synthetic fuels, to a third-party buyer. In addition, we entered into an
agreement to operate the Ceredo facility on behalf of the buyer. At closing, we
received cash proceeds of $10 million and a non-recourse note receivable of $54
million. Payments on the note were due as we produced and sold qualifying
synthetic fuels on behalf of the buyer. In accordance with the terms of the
agreement, we received payments on the note related to 2007 production of $49
million during the year ended December 31, 2007, and a final payment of $5
million during the three months ended March 31, 2008. The note had an interest
rate equal to the three-month London Inter Bank Offering Rate (LIBOR) rate plus
1%. The estimated fair value of the note at the inception of the transaction was
$48 million. Under the terms of the agreement, the purchase price was reduced by
$7 million during the three months ended March 31, 2008, based on the final
value of the 2007 Section 29/45 tax credits.
  Pursuant
to the terms of the disposal agreement, the buyer had the right to unwind the
transaction if an Internal Revenue Service (IRS) reconfirmation private letter
ruling was not received by November 9, 2007, or if certain adverse changes in
tax law, as defined in the agreement, occurred before November 19, 2007. The IRS
reconfirmation private letter ruling was received on October 29, 2007, and no
adverse change in tax law occurred prior to November 19, 2007. During the three
months ended March 31, 2008, we recorded gains on disposal of $5 million based
on the final value of the 2007 Section 29/45K tax credits. The operations of
Ceredo ceased as of
  25
  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.
  On the
date of the transaction, the carrying value of the disposed ownership interest
totaled $37 million, which consisted primarily of the fair value of crude oil
call options purchased in January 2007. Subsequent to the disposal, we remained
the primary beneficiary of Ceredo and continued to consolidate Ceredo in
accordance with FIN 46R, but recorded a 100 percent minority interest. 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 gain
on disposal in future periods. See general discussion of guarantees at Note
13B.
  4.
              REGULATORY
      MATTERS
  A.
                PEC
      RETAIL RATE MATTERS
 BASE
RATES
  PEC’s
base rates are subject to the regulatory jurisdiction of the NCUC and SCPSC. In
June 2002, the North Carolina Clean Smokestacks Act (Clean Smokestacks Act) was
enacted in North Carolina requiring the state's electric utilities to reduce the
emissions of nitrogen oxides (NOx) and sulfur dioxide (SO2) from
their North Carolina coal-fired power plants in phases by 2013. The Clean
Smokestacks Act froze North Carolina electric utility base rates for a five-year
period, which ended December 31, 2007, unless there were extraordinary events
beyond the control of the utilities or unless the utilities persistently earned
a return substantially in excess of the rate of return established and found
reasonable by the NCUC in the respective utility’s last general rate case. There
were no adjustments to PEC’s base rates during the five-year period ended
December 31, 2007. Subsequent to 2007, PEC’s current North Carolina base rates
are continuing subject to traditional cost-based rate regulation.
  During
the rate freeze period, the legislation provided for a minimum amortization and
recovery of 70 percent of the original estimated compliance costs of $813
million (or $569 million) while providing significant flexibility in the amount
of annual amortization recorded from none up to $174 million per year. On March
23, 2007, PEC filed a petition with the NCUC requesting that it be allowed to
amortize the remaining 30 percent (or $244 million) of the original estimated
compliance costs for the Clean Smokestacks Act during 2008 and 2009, with
discretion to amortize up to $174 million in either year. For the three months
ended March 31, 2008 and 2007, PEC recognized amortization of $15 million and $8
million, respectively. PEC has recognized $584 million in cumulative
amortization through March 31, 2008.
  Additionally,
among other things, PEC requested in its March 23, 2007 petition that the NCUC
allow PEC to include in its rate base those eligible compliance costs exceeding
the original estimated compliance costs and that PEC be allowed to accrue
allowance for funds used during construction (AFUDC) on all eligible compliance
costs in excess of the original estimated compliance costs. PEC also requested
that any prudency review of PEC’s environmental compliance costs be deferred
until PEC’s next ratemaking proceeding in which PEC seeks to adjust its base
rates. On October 22, 2007, PEC filed with the NCUC a settlement agreement with
the NCUC Public Staff, the Carolina Utility Customers Associations (CUCA) and
the Carolina Industrial Group for Fair Utility Rates II (CIGFUR) supporting
PEC’s proposal. The NCUC held a hearing on this matter on October 30, 2007. On
December 20, 2007, the NCUC approved the settlement agreement on a provisional
basis, with the NCUC indicating that it intended to initiate a review in 2009 to
consider all reasonable alternatives and proposals related to PEC’s recovery of
its Clean Smokestacks Act compliance costs in excess of the original estimated
costs of $813 million. Additionally, the NCUC ordered that no portion of Clean
Smokestacks Act compliance costs directly assigned, allocated or otherwise
attributable to another jurisdiction shall be recovered from PEC’s retail North
Carolina customers, even if recovery of these costs is disallowed or denied, in
whole or in part, in another jurisdiction. We cannot predict the outcome of
PEC’s recovery of eligible compliance costs exceeding the original estimated
compliance costs.
  See Note
12B for additional information about the Clean Smokestacks Act.
  26
  FUEL
COST RECOVERY
  On April
30, 2008, PEC filed with the SCPSC for an increase in the fuel rate charged to
its South Carolina ratepayers. PEC is asking the SCPSC to approve a $39 million
increase in fuel rates for under-recovered fuel costs associated with prior year
settlements and to meet future expected fuel costs. If approved, the increase
would take effect July 1, 2008 and would increase residential electric bills by
$5.86 per 1,000 kilowatt-hours (kWh), or 6.1 percent, for fuel cost recovery. A
hearing on the matter has been scheduled by the SCPSC for June 12, 2008. We
cannot predict the outcome of this matter.
  OTHER
MATTERS
  During
2007, the North Carolina legislature passed comprehensive energy legislation,
which became law on August 20, 2007. Among other provisions, the law allows the
utility to recover the costs of new demand-side management (DSM) and
energy-efficiency programs through an annual DSM clause. The law allows PEC to
capitalize those costs
  that are
intended to produce future benefits and authorizes the NCUC to approve other
forms of financial incentives to the utility for DSM and energy-efficiency
programs. DSM programs include, but are not limited to, any program or
initiative that shifts the timing of electricity use from peak to nonpeak
periods and includes load management, electricity system and operating controls,
direct load control, interruptible load and electric system equipment and
operating controls. Energy-efficiency programs help our customers reduce energy
use and reduce the emissions that contribute to global climate change. PEC has
begun implementing a series of DSM and energy-efficiency programs and deferred
an immaterial amount of implementation and program costs for future recovery. On
April 29 and May 1, 2008, PEC filed for NCUC approval of a total of five DSM and
energy-efficiency programs, including the EnergyWiseTM and distribution system
demand response programs discussed below.
  On April
29, 2008, PEC filed for approval by the NCUC of its EnergyWiseTM program, which
is a residential program that offers customers an incentive to permit PEC to
remotely adjust central air conditioning and heat pumps in PEC’s eastern control
area and electric resistance heating and water heaters in PEC’s western control
area in order to reduce peak demand. PEC’s goal for EnergyWiseTM is to have the
capability to reduce peak electricity demand by 200 MW by 2017.
 
 Also on
April 29, 2008, PEC filed for NCUC approval of its distribution system demand
response program, which will provide additional capability for reducing and
shifting peak electricity demand. The program also will reduce the level of
natural electricity loss experienced over long distribution feeder lines,
thereby eliminating the need for additional power generation to compensate for
the line losses. PEC anticipates that the program will require an
investment of approximately $260 million over five years and is expected to
reduce peak demand by 250 MW. This distribution system investment is part of
PEC’s broader “Smart Grid” strategy and is expected to provide a foundation for
additional initiatives, including enhanced system reliability (through faster
outage isolation and response) and new capabilities for incorporating renewable
energy resources and other distributed generation into PEC’s energy mix. Such
costs are expected to be recovered under the provisions of the North Carolina
comprehensive energy legislation.
 
 We cannot
predict the outcome of the April 29 and May 1, 2008 filings or whether the
proposed programs will produce the expected operational and economic
results.
 
 PEC filed
a petition on November 30, 2007, with the SCPSC seeking authorization to create
a deferred account for DSM and energy-efficiency expenses. On December 21, 2007,
the SCPSC issued an order granting PEC’s petition. As a result, PEC has deferred
an immaterial amount of implementation and program costs for future recovery in
the South Carolina jurisdiction. PEC anticipates applying for a DSM and
energy-efficiency clause to recover the costs of these programs in 2008. We
cannot predict the outcome of this matter.
  On
February 29, 2008, the NCUC issued an order adopting final rules for
implementing North Carolina’s comprehensive energy legislation. These rules
provide filing requirements associated with the legislation. The order requires
PEC to submit its first annual North Carolina Renewable Energy and Energy
Efficiency Portfolio Standard (REPS) compliance plan by September 1, 2008, as
part of its integrated resource plan. Under the new rules, beginning in 2009,
PEC will also be required to file an annual REPS compliance report demonstrating
the actions it has taken to comply with the REPS requirement. The rules measure
compliance with the REPS requirement via renewable energy certificates (REC)
earned after January 1, 2008. The NCUC will pursue a third-party REC
  27
 tracking
system, but will not develop or require participation in a REC trading platform
at this time. The order also establishes a schedule and filing requirements for
DSM and energy-efficiency cost
recovery and financial incentives. Rates for the DSM and energy-efficiency
clause and the REPS clause will be set based on projected costs with true-up
provisions.
 
 On April
30, 2008, PEC filed an Application for Certificate of Public Convenience and
Necessity with the NCUC to construct a 600 MW combined cycle duel fuel capable
generating facility at its Richmond County generation site. We cannot
predict the outcome of this matter.
 
 On April
30, 2008, PEC submitted a revised Open Access Transmission Tariff (OATT)
filing, including a settlement agreement, with the FERC requesting an increase
in transmission rates. The purpose of the filing was to implement formula rates
for the PEC OATT in order to more accurately reflect the costs that PEC incurs
in providing
transmission service. In the filing, PEC proposed to move from a fixed revenue
requirement to a formula rate, which allows for transmission rates to be updated
each year based on the prior year’s actual costs. Settlement discussions were
held with major customers prior to the filing and a settlement agreement was
reached on all issues. The settlement proposed a formula rate with a rate of
return on equity of 10.8 percent as well as recovery of the wholesale portion of
the terminated GridSouth Transco, LLC (GridSouth) project startup costs over
five years. If approved by FERC, the new rates would be effective July 1, 2008,
and PEC estimates the impact of the new rates will increase 2008 revenues by $6
million to $8 million. We cannot predict the outcome of this
matter.
 
 In 2000,
the FERC issued Order 2000, which set minimum characteristics and functions that
regional transmission organizations (RTOs) must meet, including independent
transmission service. In October 2000, as a result of Order 2000, PEC, along
with Duke Energy Corporation and South Carolina Electric & Gas Company,
filed an application with the FERC for approval of an RTO, GridSouth. In July
2001, the FERC issued an order provisionally approving GridSouth. However, in
July 2001, the FERC issued orders recommending that companies in the
southeastern United States engage in mediation to develop a plan for a single
RTO. PEC participated in the mediation; no consensus was reached on creating a
southeast RTO. On August 11, 2005, the GridSouth participants notified the FERC
that they had terminated the GridSouth project. By order issued October 20,
2005, the FERC terminated the GridSouth proceeding.
 
 On
November 16, 2007, PEC petitioned the NCUC to allow it to establish a regulatory
asset for PEC’s development costs of GridSouth pending disposition in a general
rate proceeding. On January 14, 2008, the NCUC issued an order requesting
interested parties to file comments regarding PEC’s petition on or before
January 28, 2008. On February 11, 2008, PEC filed response comments. On December
20, 2007, the NCUC issued an order for one of the other GridSouth partners. As
part of that order, the NCUC ruled that the utility’s GridSouth development
costs should be amortized and recovered over a 10-year period beginning June
2002. Until the NCUC rules upon PEC’s petition, PEC will apply the same
accounting treatment to its GridSouth development costs. PEC’s recorded
investment in GridSouth totaled $22 million at March 31, 2008 and December 31,
2007. PEC expects to recover its GridSouth development costs based on precedent
regulatory proceedings.  We cannot predict the outcome of this
matter.
 
 B. 
PEF RETAIL RATE MATTERS
  PASS-THROUGH
CLAUSE COST RECOVERY
  On August
10, 2006, Florida’s Office of Public Counsel (OPC) filed a petition with the
FPSC asking that the FPSC require PEF to refund to ratepayers $143 million, plus
interest, of alleged excessive past fuel recovery charges and SO2 allowance
costs during the period 1996 to 2005. The OPC subsequently revised its claim to
$135 million, plus interest. The OPC claimed that although Crystal River Unit 4
and Crystal River Unit 5 (CR4 and CR5) were designed to burn a blend of coals,
PEF failed to act to lower ratepayers’ costs by purchasing the most economical
blends of coal. During the period specified in the petition, PEF’s costs
recovered through fuel recovery clauses were annually reviewed for prudence and
approval by the FPSC. On July 31, 2007, the FPSC heard this matter. On October
10, 2007, the FPSC issued its order rejecting most of the OPC’s contentions.
However, the 4-1 majority found that PEF had not been prudent in purchasing a
portion of its coal requirements during the period from 2003 to 2005.
Accordingly, the FPSC ordered PEF to refund its ratepayers approximately $14
million, inclusive of interest, over a 12-month period beginning January 1,
2008. For the year ended December 31, 2007, PEF recorded a pre-tax
  28
  other
operating expense of $12 million, interest expense of $2 million and an
associated $14 million regulatory liability included within PEF’s deferred fuel
cost at December 31, 2007. On October 25, 2007, the OPC requested the FPSC to
reconsider its October 10, 2007 order asserting that the FPSC erred in not
ordering a larger refund. PEF filed its opposition to the OPC’s request on
November 1, 2007. On February 12, 2008, the FPSC denied the OPC’s request for
reconsideration. Neither PEF nor OPC filed an appeal to the Florida Supreme
Court of the FPSC’s October 10, 2007 order. The FPSC also ordered PEF to address
whether it was prudent in its 2006 and 2007 coal purchases for CR4 and CR5. On
October 4, 2007, PEF filed a motion to establish a separate docket on the
prudence of its coal purchases for CR4 and CR5 for the years 2006 and 2007. On
October 17, 2007, the FPSC granted that motion.
The OPC filed testimony in support of its position to require PEF to refund at
least $14 million for alleged excessive fuel recovery charges for 2006 coal
purchases. PEF believes its coal procurement practices have been prudent. We
anticipate that a hearing will be held on the 2006 and 2007 coal purchases in
January 2009. We cannot predict the outcome of this matter.
  On
September 22, 2006, PEF filed a petition with the FPSC for Determination of Need
to uprate Crystal River Unit No. 3 Nuclear Plant (CR3), bid rule exemption and
recovery of the revenue requirements of the uprate through PEF’s fuel recovery
clause. To the extent the expenditures are prudently incurred, PEF’s investment
in the CR3 uprate is eligible for recovery through base rates. PEF’s petition
would allow for more prompt recovery. The multi-stage uprate will increase CR3’s
gross output by approximately 180 MW by 2012. PEF received NRC approval for a
license amendment and implemented the first stage’s design modification on
January 31, 2008, and will apply for the required license amendment for the
third stage’s design modification. The petition filed with the FPSC included
estimated project costs of approximately $382 million. These cost estimates may
continue to change depending upon the results of more detailed engineering and
development work and increased material, labor and equipment costs. On February
8, 2007, the FPSC issued an order approving the need certification petition and
bid rule exemption. The request for recovery through PEF’s fuel recovery clause
was transferred to a separate docket filed on January 16, 2007. On February 2,
2007, intervenors filed a motion to abate the cost-recovery portion of PEF’s
request. On February 9, 2007, PEF requested that the FPSC deny the intervenors’
motion as legally deficient and without merit. On March 27, 2007, the FPSC
denied the motion to abate and directed the staff of the FPSC to conduct a
hearing to determine whether the revenue requirements of the uprate should be
recovered through the fuel recovery clause. On May 4, 2007, PEF filed amended
testimony clarifying the scope of the project. The FPSC held a hearing on this
matter on August 7 and 8, 2007. The staff of the FPSC recommended that PEF be
allowed to recover prudent and reasonable costs of Phase 1, estimated at $6
million of direct costs, through the fuel clause. The staff of the FPSC
recommended that the costs of all other phases, estimated at $376 million, be
considered in a base rate proceeding. On October 19, 2007, PEF filed a notice of
withdrawal of its cost-recovery petition with the FPSC. On November 21, 2007,
PEF filed a petition with the FPSC seeking cost recovery under Florida’s
comprehensive energy legislation enacted in 2006, and the FPSC’s new nuclear
cost-recovery rule. On February 13, 2008, PEF filed a notice of withdrawal of
its cost-recovery petition with the FPSC. On February 29, 2008, PEF filed a
petition for recovery of costs incurred in 2007 and 2006 under Florida’s
comprehensive energy legislation and the FPSC’s nuclear cost-recovery rule based
on the regulatory precedence established by a FPSC order to an unaffiliated
Florida utility for a nuclear uprate project. The FPSC is scheduled to vote on
this matter by October 2008. We cannot predict the outcome of this
matter.
  On May 1,
2008, PEF filed with the FPSC for an increase in the capacity cost-recovery
charge under the FPSC nuclear cost-recovery rule. PEF is asking the FPSC to
approve a $25 million increase in the capacity cost recovery revenue
requirement for costs associated with the CR3 uprate. If approved, the
increase would take effect with the first billing cycle for 2009 and would
increase residential electric bills by $0.70 per 1,000 kWh. Also included in
this filing was a revision to the estimate provided in the need determination
proceeding to include indirect costs, for a total original estimate of $439
million. After PEF's completion of a transmission study and additional
engineering studies, the current project estimate is $364 million. A hearing on
the matter has been scheduled by the FPSC for September 2008, and the FPSC is
scheduled to vote on this matter by October 2008. We cannot predict the
outcome of this matter.
  OTHER
MATTERS
  On March
11, 2008, PEF filed a petition for an affirmative Determination of Need for its
proposed Levy Units 1 and 2 nuclear power plants, together with the associated
facilities, including transmission lines and substation facilities. Levy Units 1
and 2 are needed to maintain electric system reliability and integrity, fuel and
generating diversity and
  29
  to
continue to provide adequate electricity to its ratepayers at a reasonable cost.
Levy Units 1 and 2 will be advanced passive light water nuclear reactors, each
with a generating capacity of approximately 1,092 MW (summer rating). PEF
proposes to place Levy Unit 1 in service by June 2016 and Levy Unit 2 in service
by June 2017. The filed, non-binding project cost estimate for Levy Units 1 and
2 is approximately $14 billion for generating facilities and approximately $3
billion for associated transmission facilities. A hearing is scheduled for May
21-23, 2008, and a vote by the FPSC is scheduled for July 15, 2008. We cannot
predict the outcome of this matter.
  On March
11, 2008, PEF also filed a petition with the FPSC to open a discovery docket
regarding the actual and projected costs of the proposed Levy nuclear project.
PEF filed the petition to assist the FPSC in the timely and adequate review of
the projects costs recoverable under the FPSC nuclear cost-recovery rule. On May
1, 2008, PEF filed a petition for recovery of both preconstruction and carrying
charges on construction costs incurred or anticipated to be incurred during 2008
and 2009. Additionally, the filing included site selection costs of $38million. Subsequent to an affirmative
determination of need from the FPSC on the Levy nuclear project, PEF intends to
file a formal petition to recover all prudently incurred costs under the FPSC
nuclear cost-recovery rule. A decision by the FPSC on PEF’s 2008 cost-recovery
filing is expected by October 2008. We cannot predict the outcome of this
matter.
  5.
              EQUITY AND
      COMPREHENSIVE INCOME
  A. 
EARNINGS PER COMMON SHARE
  A
reconciliation of our weighted-average number of common shares outstanding for
basic and dilutive earnings per share purposes follows:
 Three
      Months Ended March 31,(in
      millions)
              
              2008
              
              
              2007Weighted-average
      common shares – basic
              
              
              259
              
              
              
              254Net
      effect of dilutive stock-based compensation plans
              
              
              –
              
              
              
              1Weighted-average
      shares – fully dilutive
              
              
              259
              
              
              
              255
 
 B.  COMPREHENSIVE
INCOME
  Progress
      EnergyThree
      Months Ended March 31,(in
      millions)
              
              2008
              
              
              2007Net
      income
              
              $
              209
              
              
              $
              275Other
      comprehensive income (loss)Reclassification
      adjustments included in net incomeChange
      in cash flow hedges (net of tax expense of $-)
              
              
              1
              
              
              
              –Change
      in unrecognized items for pension and other postretirement benefits (net
      of tax expense of $-)
              
              
              –
              
              
              
              1Net
      unrealized losses on cash flow hedges (net of tax benefit of
      $6)
              
              
              (9
              )
              
              
              –Other
      (net of tax benefit of $3)
              
              
              –
              
              
              
              (2
              )Other
      comprehensive loss
              
              
              (8
              )
              
              
              (1
              )Comprehensive
      income
              
              $
              201
              
              
              $
              274
  30
  PECThree
      Months Ended March 31,(in
      millions)
              
              2008
              
              
              2007Net
      income
              
              $
              123
              
              
              $
              124Other
      comprehensive lossNet
      unrealized losses on cash flow hedges (net of tax benefit of $3 and $1,
      respectively)
              
              
              (5
              )
              
              
              (1
              )Other
      (net of tax benefit of $1)
              
              
              –
              
              
              
              (4
              )Other
      comprehensive loss
              
              
              (5
              )
              
              
              (5
              )Comprehensive
      income
              
              $
              118
              
              
              $
              119
 
 PEFThree
      Months Ended March 31,(in
      millions)
              
              2008
              
              
              2007Net
      income
              
              $
              67
              
              
              $
              61Other
      comprehensive lossNet
      unrealized losses on cash flow hedges (net of tax benefit of
      $3)
              
              
              (4
              )
              
              
              –Other
      comprehensive loss
              
              
              (4
              )
              
              
              –Comprehensive
      income
              
              $
              63
              
              
              $
              61
  C.  COMMON
STOCK
  At
December 31, 2007, we had 500 million shares of common stock authorized under
our charter, of which approximately 260 million were outstanding. At December
31, 2007, we had approximately 50 million unissued shares of common stock
reserved, primarily to satisfy the requirements of our stock plans. In 2002, the
board of directors authorized meeting the requirements of the Progress Energy
401(k) Savings and Stock Ownership Plan (401(k)) and the Investor Plus Stock
Purchase Plan with original issue shares. For the three months ended March 31,
2008 and 2007, respectively, we issued approximately 0.5 million shares and 1.5
million shares of common stock resulting in approximately $20 million and $65
million in proceeds. Included in these amounts were approximately 0.4 million
shares and 0.2 millions shares, respectively, for proceeds of approximately $19
million and $11 million, respectively, to meet the requirements of the 401(k)
and the Investor Plus Stock Purchase Plan.
  6.
              DEBT AND CREDIT
      FACILITIES AND FINANCING
ACTIVITIES
  Material
changes, if any, to Progress Energy’s, PEC’s and PEF’s debt and credit
facilities and financing activities since December 31, 2007, are described
below.
  On
February 1, 2008, PEF paid at maturity $80 million of its 6.875% First Mortgage
Bonds with available cash on hand and commercial paper borrowings.
  On March
12, 2008, PEC and PEF amended their revolving credit agreements (RCA) with a
syndication of financial institutions to extend the termination date by one
year. The extensions were effective for both utilities on March 28, 2008. PEC’s
RCA is now scheduled to expire on June 28, 2011, and PEF’s RCA is now scheduled
to expire on March 28, 2011.
  On March
13, 2008, PEC issued $325 million of First Mortgage Bonds, 6.30% Series due
2038. The proceeds were used to repay the maturity of PEC’s $300 million 6.650%
Medium-Term Notes, Series D, due April 1, 2008 and the remainder was placed in
temporary investments for general corporate use as needed.
  On April
14, 2008, we amended our RCA with a syndication of financial institutions to
extend the termination date by one year.The extension was effective onMay 3, 2008. Our RCA is now
scheduled to expire on May 3, 2012.
  31
  7.
              FAIR VALUE
      MEASUREMENTS
  In
September 2006, the FASB issued SFAS No. 157, which defines fair value,
establishes a framework for measuring fair value under GAAP, and requires
enhanced disclosures about assets and liabilities carried at fair value. SFAS
No. 157 also establishes a fair value hierarchy that categorizes and prioritizes
the inputs that should be used to estimate fair value. In February 2008, the
FASB issued FSP No. FAS 157-2, “Effective Date of FASB Statement No. 157,” which
delays for us the effective date of SFAS No. 157 until January 1, 2009, for all
nonfinancial assets and nonfinancial liabilities, except for those that are
recognized or disclosed at fair value in the financial statements on a recurring
basis (at least annually).
  We
implemented SFAS No. 157 as of January 1, 2008, for all recurring financial
assets and liabilities. The adoption of SFAS No. 157 for recurring financial
assets and liabilities did not have a material impact on our or the Utilities'
financial position or results of operations. We utilized the deferral provision
of FSP No. FAS 157-2 for all nonrecurring nonfinancial assets and
liabilities within its scope. Major categories of our assets and liabilities to
which the deferral applies include reporting units and long-lived asset groups
measured at fair value for impairment purposes, asset retirement obligations
initially recognized at fair value, and nonfinancial liabilities for exit and
disposal costs and indemnifications initially measured at fair value. We do not
expect the January 1, 2009 adoption of SFAS No. 157 for nonrecurring
nonfinancial assets and liabilities to have a material impact on our or the
Utilities' financial position or results of operations.
  SFAS No.
157 defines fair value as the price that would be received to sell an asset or
paid to transfer a liability in an orderly transaction between market
participants at the measurement date (i.e., an exit price). SFAS No. 157 permits
the use of a mid-market pricing convention (the mid-point price between bid and
ask prices) as a practical expedient and requires the use of market data or
assumptions that market participants would use in pricing the asset or
liability, including assumptions about risk and the risks inherent in the inputs
to the valuation technique. These inputs can be readily observable, corroborated
by market data, or generally unobservable. SFAS No. 157 requires that valuation
techniques maximize the use of observable inputs and minimize the use of
unobservable inputs.
  SFAS No.
157 establishes a fair value hierarchy that prioritizes the inputs used to
measure fair value, and requires fair value measurements to be categorized based
on the observability of those inputs. The hierarchy gives the highest priority
to unadjusted quoted prices in active markets for identical assets or
liabilities (Level 1 inputs) and the lowest priority to unobservable inputs
(Level 3 inputs). The three levels of the fair value hierarchy defined by SFAS
No. 157 are as follows:
  Level 1 –
The pricing inputs are unadjusted quoted prices in active markets for identical
assets or liabilities as of the reporting date. Active markets are those in
which transactions for the asset or liability occur in sufficient frequency and
volume to provide pricing information on an ongoing basis. Level 1 primarily
consists of financial instruments such as exchange-traded derivatives and listed
equities.
  Level 2 –
The pricing inputs are inputs other than quoted prices included within Level 1
that are observable for the asset or liability, either directly or indirectly.
Level 2 includes those financial instruments that are valued using models or
other valuation methodologies. These models are primarily industry-standard
models that consider various assumptions, including quoted forward prices for
commodities, time value, volatility factors, and current market and contractual
prices for the underlying instruments, as well as other relevant economic
measures. Substantially all of these assumptions are observable in the
marketplace throughout the full term of the instrument, can be derived from
observable data or are supported by observable levels at which transactions are
executed in the marketplace. Instruments in this category include
non-exchange-traded derivatives such as over-the-counter forwards, swaps and
options, certain marketable debt securities, and financial instruments traded in
less than active markets.
  Level 3 –
The pricing inputs include significant inputs that are generally less observable
from objective sources. These inputs may be used with internally developed
methodologies that result in management’s best estimate of fair value. Level 3
instruments may include longer-term instruments that extend into periods where
quoted prices or other observable inputs are not available. At each balance
sheet date, we perform an analysis of all instruments subject to SFAS No. 157
and include in Level 3 all of those whose fair value is based on significant
unobservable inputs.
  32
  The
following tables set forth by level within the fair value hierarchy our and the
Utilities’ financial assets and liabilities that were accounted for at fair
value on a recurring basis as of March 31, 2008. As required by SFAS No. 157,
financial assets and liabilities are classified in their entirety based on the
lowest level of input that is significant to the fair value measurement. Our
assessment of the significance of a particular input to the fair value
measurement requires judgment, and may affect the valuation of fair value assets
and liabilities and their placement within the fair value hierarchy
levels.
  Progress
      Energy(in
      millions)
              
              Level
      1
              
              
              Level
      2
              
              
              Level
      3
              
              
              TotalAssets:Commodity
      derivatives
              
              $
              –
              
              
              $
              372
              
              
              $
              55
              
              
              $
              427Nuclear
      decommissioning trust funds
              
              
              785
              
              
              
              528
              
              
              
              –
              
              
              
              1,313Other
      marketable securities
              
              
              9
              
              
              
              40
              
              
              
              –
              
              
              
              49
 
 Total
      assets
              
              $
              794
              
              
              $
              940
              
              
              $
              55
              
              
              $
              1,789
 Liabilities:Commodity
      derivatives
              
              $
              –
              
              
              $
              (10
              )
              
              $
              –
              
              
              $
              (10
              )Interest
      rate derivatives
              
              
              –
              
              
              
              (7
              )
              
              
              –
              
              
              
              (7
              )CVO
      derivatives
              
              
              –
              
              
              
              (34
              )
              
              
              –
              
              
              
              (34
              )Total
      liabilities
              
              $
              –
              
              
              $
              (51
              )
              
              $
              –
              
              
              $
              (51
              )
  PEC(in
      millions)
              
              Level
      1
              
              
              Level
      2
              
              
              Level
      3
              
              
              TotalAssets:Commodity
      derivatives
              
              $
              –
              
              
              $
              37
              
              
              $
              12
              
              
              $
              49Nuclear
      decommissioning trust funds
              
              
              444
              
              
              
              327
              
              
              
              –
              
              
              
              771Total
      assets
              
              $
              444
              
              
              $
              364
              
              
              $
              12
              
              
              $
              820Liabilities:Commodity
      derivatives
              
              $
              –
              
              
              $
              (1
              )
              
              $
              –
              
              
              $
              (1
              )Total
      liabilities
              
              $
              –
              
              
              $
              (1
              )
              
              $
              –
              
              
              $
              (1
              )
 
 PEF(in
      millions)
              
              Level
      1
              
              
              Level
      2
              
              
              Level
      3
              
              
              TotalAssets:Commodity
      derivatives
              
              $
              –
              
              
              $
              335
              
              
              $
              43
              
              
              $
              378Nuclear
      decommissioning trust funds
              
              
              341
              
              
              
              201
              
              
              
              –
              
              
              
              542Total
      assets
              
              $
              341
              
              
              $
              536
              
              
              $
              43
              
              
              $
              920Liabilities:Commodity
      derivatives
              
              $
              –
              
              
              $
              (9
              )
              
              $
              –
              
              
              $
              (9
              )Interest
      rate derivatives
              
              
              –
              
              
              
              (7
              )
              
              
              –
              
              
              
              (7
              )Total
      liabilities
              
              $
              –
              
              
              $
              (16
              )
              
              $
              –
              
              
              $
              (16
              )
  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
  33
  fair
value of the derivative. Such derivatives are classified within Level 3. See
Note 9 for discussion of risk management activities and derivative
transactions.
  Nuclear
decommissioning trust funds reflect the assets of the Utilities’ nuclear
decommissioning trusts, as discussed in Note 13 of the 2007 Form 10-K. The
assets of the trusts are invested primarily in exchange-traded equity securities
(classified within Level 1) and marketable debt securities, most of which are
valued using Level 1 inputs for similar instruments, and are classified within
Level 2.
  Other
marketable securities represent available-for-sale debt and equity securities
used to fund certain employee benefit costs.
  We issued
Contingent Value Obligations (CVOs) in connection with the acquisition of
Florida Progress Corporation (Florida Progress), as discussed in Note 15 in the
2007 Form 10-K. The CVOs are derivatives recorded at fair value based on quoted
prices from a less than active market, and are classified as Level
2.
  The
following tables set forth a reconciliation of changes in the fair value of our
and the Utilities’ commodity derivatives classified as Level 3 in the fair value
hierarchy.
  Progress
      Energy(in
      millions)Derivatives,
      net at January 1, 2008
              
              $
              26Total
      gains (losses), realized and unrealized:Included
      in earnings
              
              
              –Included
      in other comprehensive income
              
              
              –Deferred
      as regulatory assets and liabilities, net
              
              
              29Purchases,
      issuances and settlements, net
              
              
              –Transfers
      in (out) of Level 3, net
              
              
              –Derivatives,
      net at March 31, 2008
              
              $
              55
  PEC(in
      millions)Derivatives,
      net at January 1, 2008
              
              $
              6Total
      gains (losses), realized and unrealized:Included
      in earnings
              
              
              –Included
      in other comprehensive income
              
              
              –Deferred
      as regulatory assets and liabilities, net
              
              
              6Purchases,
      issuances and settlements, net
              
              
              –Transfers
      in (out) of Level 3, net
              
              
              –Derivatives,
      net at March 31, 2008
              
              $
              12
 
 PEF(in
      millions)Derivatives,
      net at January 1, 2008
              
              $
              20Total
      gains (losses), realized and unrealized:Included
      in earnings
              
              
              –Included
      in other comprehensive income
              
              
              –Deferred
      as regulatory assets and liabilities, net
              
              
              23Purchases,
      issuances and settlements, net
              
              
              –Transfers
      in (out) of Level 3, net
              
              
              –Derivatives,
      net at March 31, 2008
              
              $
              43
 
 Unrealized
gains and losses on 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
  34
 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
period.
  8.
              BENEFIT
      PLANS
  We have
noncontributory defined benefit retirement plans that provide pension benefits
for substantially all full-time employees. We also have supplementary defined
benefit pension plans that provide benefits to higher-level employees. In
addition to pension benefits, we provide contributory other postretirement
benefits (OPEB), including certain health care and life insurance benefits, for
retired employees who meet specified criteria. The components of the net
periodic benefit cost for the respective Progress Registrants for the three
months ended March 31 were:
  Progress
      EnergyPension
      Benefits
              
              
              Other
      Postretirement
                Benefits(in
      millions)
              
              2008
              
              
              2007
              
              
              2008
              
              
              2007Service
      cost
              
              $
              12
              
              
              $
              11
              
              
              $
              2
              
              
              $
              2Interest
      cost
              
              
              31
              
              
              
              30
              
              
              
              8
              
              
              
              9Expected
      return on plan assets
              
              
              (41
              )
              
              
              (39
              )
              
              
              (2
              )
              
              
              (1
              )Amortization
      of actuarial loss (a)
              
              
              3
              
              
              
              4
              
              
              
              1
              
              
              
              1Other
      amortization, net (a)
              
              
              –
              
              
              
              –
              
              
              
              1
              
              
              
              1Net
      periodic cost
              
              $
              5
              
              
              $
              6
              
              
              $
              10
              
              
              $
              12
 
 (a)Adjusted to reflect PEF’s rate treatment. See Note 16B in the 2007 Form
10-K.
 
 PECPension
      Benefits
              
              
              Other
      Postretirement
                Benefits(in
      millions)
              
              2008
              
              
              2007
              
              
              2008
              
              
              2007Service
      cost
              
              $
              6
              
              
              $
              5
              
              
              $
              1
              
              
              $
              1Interest
      cost
              
              
              14
              
              
              
              14
              
              
              
              4
              
              
              
              5Expected
      return on plan assets
              
              
              (16
              )
              
              
              (15
              )
              
              
              (1
              )
              
              
              (1
              )Amortization
      of actuarial loss
              
              
              2
              
              
              
              3
              
              
              
              –
              
              
              
              1Net
      periodic cost
              
              $
              6
              
              
              $
              7
              
              
              $
              4
              
              
              $
              6
 
 PEFPension
      Benefits
              
              
              Other
      Postretirement
                Benefits(in
      millions)
              
              2008
              
              
              2007
              
              
              2008
              
              
              2007Service
      cost
              
              $
              4
              
              
              $
              4
              
              
              $
              1
              
              
              $
              1Interest
      cost
              
              
              13
              
              
              
              13
              
              
              
              3
              
              
              
              3Expected
      return on plan assets
              
              
              (21
              )
              
              
              (21
              )
              
              
              –
              
              
              
              –Other
      amortization, net
              
              
              –
              
              
              
              –
              
              
              
              1
              
              
              
              1Net
      periodic (benefit) cost
              
              $
              (4
              )
              
              $
              (4
              )
              
              $
              5
              
              
              $
              5
 
 9.
              RISK MANAGEMENT
      ACTIVITIES AND DERIVATIVE
TRANSACTIONS
  We are
exposed to various risks related to changes in market conditions. We have a risk
management committee that includes senior executives from various business
groups. The risk management committee is responsible for administering risk
management policies and monitoring compliance with those policies by all
subsidiaries. Under our risk policy, we may use a variety of instruments,
including swaps, options and forward contracts, to manage exposure to
fluctuations in commodity prices and interest rates. Such instruments contain
credit risk if the counterparty fails to perform under the contract. We minimize
such risk by performing credit reviews using, among other things, publicly
available credit ratings of such counterparties. Potential nonperformance by
counterparties is not expected to have a material effect on our financial
position or results of operations.
  35
  As
discussed in Note 7, in connection with the acquisition of Florida Progress
during 2000, the Parent issued 98.6 million CVOs. The CVOs are derivatives and
are recorded at fair value. The unrealized loss/gain recognized due to changes
in fair value is recorded in other, net on the Consolidated Statements of
Income. At March 31, 2008, and December, 31, 2007, the CVO liability included in
other liabilities and deferred credits on our Consolidated Balance Sheets was
$34 million.
  A. 
COMMODITY DERIVATIVES
  GENERAL
  Most of
our commodity contracts are not derivatives pursuant to SFAS No. 133 or qualify
and are elected as normal purchases or sales pursuant to SFAS No. 133.
Therefore, such contracts are not recorded at fair value.
  In 2003,
PEC recorded a $38 million pre-tax ($23 million after-tax) fair value loss
transition adjustment pursuant to the provisions of FASB Derivatives
Implementation Group Issue C20, “Interpretation of the Meaning of Not Clearly
and Closely Related in Paragraph 10(b) regarding Contracts with a Price
Adjustment Feature” (DIG Issue C20). The related liability is being amortized to
earnings over the term of the related contract (See Note 11). At March 31, 2008,
and December 31, 2007, the remaining liability was $9 million and $10 million,
respectively.
  DISCONTINUED
OPERATIONS
  On
January 8, 2007, we entered into derivative contracts to hedge economically a
portion of our 2007 synthetic fuels cash flow exposure to the risk of rising oil
prices over an average annual oil price range of $63 to $77 per barrel on a New
York Mercantile Exchange (NYMEX) basis. The notional quantity of these oil price
hedge instruments was 25 million barrels and provided protection for the
equivalent of approximately 8 million tons of 2007 synthetic fuels production.
The cost of the hedges was approximately $65 million. The contracts were
marked-to-market with changes in fair value recorded through earnings. These
contracts ended on December 31, 2007, and were settled for cash on January 8,
2008, with no material impact to 2008 earnings. Approximately 34 percent of the
notional quantity of these contracts was entered into by Ceredo. As discussed in
Notes 1C and 3F, we disposed of our 100 percent ownership interest in Ceredo on
March 30, 2007. Progress Energy is the primary beneficiary of, and continues to
consolidate Ceredo in accordance with FIN 46R, with a 100 percent minority
interest. Consequently, subsequent to the disposal there is no net earnings
impact from Ceredo’s operations, which ceased as of December 31, 2007. At
December 31, 2007, the $234 million fair value of these contracts, including $79
million at Ceredo, was included in receivables, net on the Consolidated
Balance Sheet. The contracts ended on December 31, 2007, and were settled for
cash on January 8, 2008, with no material impact to 2008 earnings. For the three
months ended March 31, 2007, we recorded net pre-tax gains of $45 million
related to these contracts, including $15 million attributable to Ceredo, of
which less than $1 million was attributed to minority interest for the portion
of the gain subsequent to disposal.
  ECONOMIC
DERIVATIVES
  Derivative
products, primarily electricity and natural gas contracts, may be entered into
from time to time for economic hedging purposes. While management believes the
economic hedges mitigate exposures to fluctuations in commodity prices, these
instruments are not designated as hedges for accounting purposes and are
monitored consistent with trading positions. We manage open positions with
strict policies that limit our exposure to market risk and require daily
reporting to management of potential financial exposures.
  The
Utilities have derivative instruments related to their exposure to price
fluctuations on fuel oil and natural gas purchases. These instruments receive
regulatory accounting treatment. Unrealized gains and losses are recorded in
regulatory liabilities and regulatory assets on the Balance Sheets,
respectively, until the contracts are settled. Once settled, any realized gains
or losses are passed through the fuel clause. During the quarters ended March
31, 2008 and 2007, PEC recorded a net realized gain of less than $1 million.
During the quarters ended March 31, 2008 and 2007, PEF recorded a net realized
gain of $16 million and a net realized loss of $17 million,
respectively.
  The
December 31, 2007 balances presented below reflect the retrospective adoption of
FSP FIN 39-1 (See Note 2).
  At March
31, 2008, the fair value of PEC’s commodity derivative instruments was recorded
as a $13 million short-term derivative asset position included in prepayments
and other current assets and $36 million long-term derivative
  36
 asset
position included in other assets and deferred debits on the PEC Consolidated
Balance Sheet. At December 31, 2007, the fair value of such instruments were
recorded as a $19 million long-term derivative asset position included in other
assets and deferred debits and a $4 million short-term derivative liability
included in other current liabilities on the PEC Consolidated Balance Sheet. PEC
had no cash collateral position at March 31, 2008 or December 31,
2007.
  At March
31, 2008, the fair value of PEF’s commodity derivative instruments was recorded
as a $204 million short-term derivative asset position included in current
derivative assets, a $174 million long-term derivative asset position included
in derivative assets, a $4 million short-term liability position included in
derivative liabilities, and a $5 million long-term derivative liability position
included in other liabilities and deferred credits on the PEF Balance Sheet. At
December 31, 2007, the fair value of such instruments were recorded as a $83
million short-term derivative asset position included in current derivative
assets, a $100 million long-term derivative asset position included in
derivative assets, a $38 million short-term liability position included in
derivative liabilities, and a $9 million long-term derivative liability position
included in other liabilities and deferred credits on the PEF Balance Sheet. PEF
had a $51 million cash collateral liability at March 31, 2008, included in other
current liabilities on the PEF Balance Sheet, and no cash collateral position at
December 31, 2007.
  CASH
FLOW HEDGES
  PEC
designates a portion of commodity derivative instruments as cash flow hedges
under SFAS No. 133. The objective for holding these instruments is to hedge
exposure to market risk associated with fluctuations in the price of power for
our forecasted sales. Realized gains and losses are recorded net in operating
revenues. At March 31, 2008, and December 31, 2007, neither we nor the Utilities
had material outstanding positions in such contracts. The ineffective portion of
commodity cash flow hedges was not material to our or the Utilities’ results of
operations for the three months ended March 31, 2008 and 2007.
  At March
31, 2008, and December 31, 2007, the amount recorded in our or PEC’s accumulated
other comprehensive income related to commodity cash flow hedges was not
material and PEF had no amount recorded in accumulated other comprehensive
income related to commodity cash flow hedges.
  B. 
INTEREST RATE
DERIVATIVES – FAIR VALUE OR CASH FLOW HEDGES
  We use
cash flow hedging strategies to reduce exposure to changes in cash flow due to
fluctuating interest rates. We use fair value hedging strategies to reduce
exposure to changes in fair value due to interest rate changes. The notional
amounts of interest rate derivatives are not exchanged and do not represent
exposure to credit loss. In the event of default by the counterparty, the
exposure in these transactions is the cost of replacing the agreements at
current market rates.
  CASH
FLOW HEDGES
  The fair
values of open interest rate hedges at March 31, 2008, and December 31, 2007,
were as follows:
 March
      31, 2008
                
                
                December
      31, 2007(in
      millions)
                
                Progress
      Energy
                
                
                PEC
                
                
                PEF
                
                
                Progress
      Energy
                
                
                PEC
                
                
                PEFFair
      value of liabilities
                
                $
                (7
                )
                
                $
                –
                
                
                $
                (7
                )
                
                $
                (12
                )
                
                $
                (12
                )
                
                $
                –
  Gains and
losses from cash flow hedges are recorded in accumulated other comprehensive
income and amounts reclassified to earnings are included in net interest charges
as the hedged transactions occur. Amounts in accumulated other comprehensive
income related to terminated hedges are reclassified to earnings as the interest
expense is recorded. The ineffective portion of interest rate cash flow hedges
for the three months ended March 31, 2008 and 2007, was not material to our or
the Utilities’ results of operations.
  The
following table presents selected information related to our interest rate cash
flow hedges included in accumulated other comprehensive income at March 31,
2008:
  37
  
 (term
      in years/millions of dollars)
              
              Progress
                Energy
              
              
              PEC
              
              
              PEFMaximum
      term
              
              Less
      than 1
              
              
              
              –
              
              
              Less
      than 1Accumulated
      other comprehensive loss, net of tax(a)
              
              $
              (31
              )
              
              $
              (15
              )
              
              $
              (12
              )Portion
      expected to be reclassified to earnings during the next12
      months(b)
              
              $
              (3
              )
              
              $
              (1
              )
              
              $
              (1
              )
 
 (a)     Includes
amounts related to terminated hedges.
 (b)
              Actual
      amounts that will be reclassified to earnings may vary from the expected
      amounts presented above as a result of changes in interest
      rates.
 
 At
December 31, 2007, including amounts related to terminated hedges, we had $24
million of after-tax deferred losses, including $12 million of after-tax
deferred losses at PEC and $8 million of after-tax deferred losses at PEF,
recorded in accumulated other comprehensive income related to interest rate cash
flow hedges.
  At
December 31, 2007, PEC had $200 million notional of interest rate cash flow
hedges. All of PEC’s forward starting swaps were terminated on March 13, 2008,
in conjunction with PEC’s issuance of $325 million of First Mortgage Bonds,
6.30% Series due 2038. The effective portion of the hedges is included in
accumulated other comprehensive income and will be amortized to interest expense
over the life of the related debt.
  In
January 2008, PEF entered into a combined $200 million notional of forward
starting swaps to mitigate exposure to interest rate risk in anticipation of
future debt issuance. On May 1, 2008, PEF entered into a $50 million notional
10-year forward starting swap and a $100 million notional 30-year forward
starting swap to mitigate exposure to interest rate risk in anticipation of
future debt issuances.
  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, 2008, and December 31, 2007, we
and the Utilities had no open interest rate fair value hedges.
  10.
              FINANCIAL INFORMATION
      BY BUSINESS SEGMENT
  Our
reportable PEC and PEF business segments are primarily engaged in the
generation, transmission, distribution and sale of electricity in portions of
North Carolina, South Carolina and Florida. These electric operations also
distribute and sell electricity to other utilities, primarily on the east coast
of the United States.
  In
addition to the reportable operating segments, the Corporate and Other segment
includes the operations of the Parent and PESC and other miscellaneous
nonregulated businesses that do not separately meet the quantitative disclosure
requirements of SFAS No. 131, “Disclosures about Segments of an Enterprise and
Related Information,” as a separate business segment. The profit or loss of our
reportable segments plus the profit or loss of Corporate and Other represents
our total income from continuing operations.
  Income of
discontinued operations is not included in the table presented below. For
comparative purposes, the prior year results have been restated to conform to
the current segment presentation. The following information is for the three
months ended March 31:
  38
  
 Income
      (Loss)Revenues
              
              
              From
      Continuing(in
      millions)
              
              Unaffiliated
              
              
              Intersegment
              
              
              Total
              
              
              Operations
              
              
              Assets2008PEC
              
              $
              1,068
              
              
              $
              –
              
              
              $
              1,068
              
              
              $
              122
              
              
              $
              12,287PEF
              
              
              996
              
              
              
              –
              
              
              
              996
              
              
              
              66
              
              
              
              10,307Corporate
      and Other
              
              
              2
              
              
              
              82
              
              
              
              84
              
              
              
              (39
              )
              
              
              16,489Eliminations
              
              
              –
              
              
              
              (82
              )
              
              
              (82
              )
              
              
              –
              
              
              
              (12,539
              )Totals
              
              $
              2,066
              
              
              $
              –
              
              
              $
              2,066
              
              
              $
              149
              
              
              $
              26,544
  2007PEC
              
              $
              1,058
              
              
              $
              –
              
              
              $
              1,058
              
              
              $
              123PEF
              
              
              1,011
              
              
              
              –
              
              
              
              1,011
              
              
              
              60Corporate
      and Other
              
              
              3
              
              
              
              86
              
              
              
              89
              
              
              
              (34
              )Eliminations
              
              
              –
              
              
              
              (86
              )
              
              
              (86
              )
              
              
              –Totals
              
              $
              2,072
              
              
              $
              –
              
              
              $
              2,072
              
              
              $
              149
 
 11.
              OTHER INCOME AND OTHER
      EXPENSE
  Other
income and expense includes interest income and other income and expense items
as discussed below. Nonregulated energy and delivery services include power
protection services and mass market programs such as surge protection, appliance
services and area light sales, and delivery, transmission and substation work
for other utilities. AFUDC equity represents the estimated equity costs of
capital funds necessary to finance the construction of new regulated assets.
CVOs unrealized gain or loss is due to changes in fair value. See Note 15 in the
2007 Form 10-K for more information on CVOs. The components of other, net as
shown on the accompanying Statements of Income were as follows:
  39
 Progress
      EnergyThree
      Months Ended March 31,(in
      millions)
              
              2008
              
              
              2007Other
      incomeNonregulated
      energy and delivery services income
              
              $
              7
              
              
              $
              9DIG
      Issue C20 amortization (see Note 9A)
              
              
              1
              
              
              
              –CVOs
      unrealized gain
              
              
              –
              
              
              
              1Investment
      gains
              
              
              1
              
              
              
              1Income
      from equity investments
              
              
              –
              
              
              
              1AFUDC
      equity
              
              
              23
              
              
              
              9Other
              
              
              3
              
              
              
              5Total
      other income
              
              
              35
              
              
              
              26Other
      expenseNonregulated
      energy and delivery services expenses
              
              
              4
              
              
              
              6Donations
              
              
              4
              
              
              
              4Investment
      losses
              
              
              3
              
              
              
              –Loss
      from equity investments
              
              
              1
              
              
              
              2Other
              
              
              5
              
              
              
              3Total
      other expense
              
              
              17
              
              
              
              15Other,
      net
              
              $
              18
              
              
              $
              11
  40
  PECThree
      Months Ended March 31,(in
      millions)
              
              2008
              
              
              2007Other
      incomeNonregulated
      energy and delivery services income
              
              $
              3
              
              
              $
              2DIG
      Issue C20 amortization (see Note 9A)
              
              
              1
              
              
              
              –Income
      from equity investments
              
              
              –
              
              
              
              2Investment
      gains
              
              
              1
              
              
              
              –AFUDC
      equity
              
              
              4
              
              
              
              2Other
              
              
              3
              
              
              
              4Total
      other income
              
              
              12
              
              
              
              10Other
      expenseNonregulated
      energy and delivery services expenses
              
              
              1
              
              
              
              2Donations
              
              
              2
              
              
              
              2Loss
      from equity investments
              
              
              1
              
              
              
              1Other
              
              
              4
              
              
              
              2Total
      other expense
              
              
              8
              
              
              
              7Other,
      net
              
              $
              4
              
              
              $
              3
  
 PEFThree
      Months Ended March 31,(in
      millions)
              
              2008
              
              
              2007Other
      incomeNonregulated
      energy and delivery services income
              
              $
              4
              
              
              $
              7AFUDC
      equity
              
              
              19
              
              
              
              7Other
              
              
              1
              
              
              
              –Total
      other income
              
              
              24
              
              
              
              14Other
      expenseNonregulated
      energy and delivery services expenses
              
              
              3
              
              
              
              5Donations
              
              
              2
              
              
              
              2Investment
      losses
              
              
              2
              
              
              
              –Total
      other expense
              
              
              7
              
              
              
              7Other,
      net
              
              $
              17
              
              
              $
              7
 
 12.
              ENVIRONMENTAL
      MATTERS
  We are
subject to regulation by various federal, state and local authorities in the
areas of air quality, water quality, control of toxic substances and hazardous
and solid wastes, and other environmental matters. We believe that we are in
substantial compliance with those environmental regulations currently applicable
to our business and operations and believe we have all necessary permits to
conduct such operations. Environmental laws and regulations frequently change
and the ultimate costs of compliance cannot always be precisely
estimated.
  A.  HAZARDOUS
AND SOLID WASTE
  The
provisions of the Comprehensive Environmental Response, Compensation and
Liability Act of 1980, as amended (CERCLA), authorize the United States
Environmental Protection Agency (EPA) to require the cleanup of hazardous waste
sites. This statute imposes retroactive joint and several liabilities. Some
states, including North Carolina, South Carolina and Florida, have similar types
of statutes. We are periodically notified by regulators, including the EPA and
various state agencies, of our involvement or potential involvement in sites
that may require investigation and/or remediation. There are presently several
sites with respect to which we have been notified of our potential liability by
the EPA, the state of North Carolina, the state of Florida, or potentially
responsible party (PRP) groups as described below in greater detail. Various
organic materials associated with the production of manufactured gas, generally
referred to as coal tar, are regulated under federal and state laws. PEC and PEF
are each PRPs at several manufactured gas plant (MGP) sites. We are also
currently in the process of assessing potential
  41
  costs and
exposures at other sites. These costs are eligible for regulatory recovery
through either base rates or cost-recovery clauses. Both PEC and PEF evaluate
potential claims against other PRPs and insurance carriers and plan to submit
claims for cost recovery where appropriate. The outcome of these potential
claims cannot be predicted. No material claims are currently pending. A
discussion of sites by legal entity follows.
  We record
accruals for probable and estimable costs related to environmental sites on an
undiscounted basis. We measure our liability for these sites based on available
evidence including our experience in investigating and remediating
environmentally impaired sites. The process often involves assessing and
developing cost-sharing arrangements with other PRPs. For all sites, as
assessments are developed and analyzed, we will accrue costs for the sites to
the extent our liability is probable and the costs can be reasonably estimated.
Because the extent of environmental impact, allocation among PRPs for all sites,
remediation alternatives (which could involve either minimal or significant
efforts), and concurrence of the regulatory authorities have not yet reached the
stage where a reasonable estimate of the remediation costs can be made, we
cannot determine the total costs that may be incurred in connection with the
remediation of all sites at this time. It is probable that current estimates
will change and additional losses, which could be material, may be incurred in
the future.
  The
following table contains information about accruals for environmental
remediation expenses described below. Accruals for probable and estimable costs
related to various environmental sites, which were included in other liabilities
and deferred credits on the Balance Sheets, were:
 (in
      millions)
              
              March
      31, 2008
              
              
              December
      31, 2007PECMGP
      and other sites(a)
              
              $
              15
              
              
              $
              16PEFRemediation
      of distribution and substation transformers
              
              
              27
              
              
              
              31MGP
      and other sites
              
              
              17
              
              
              
              17Total
      PEF environmental remediation accruals(b)
              
              
              44
              
              
              
              48Total
      Progress Energy environmental remediation accruals
              
              $
              59
              
              
              $
              64
 
 (a)
              Expected
      to be paid out over one to five
years.
 (b)
              Expected
      to be paid out over one to fifteen
years.
 
 PROGRESS
ENERGY
  In
addition to the Utilities’ sites, discussed under “PEC” and “PEF” below, our
environmental sites include the following related to our nonregulated
operations.
  On March
24, 2005, we completed the sale of our Progress Rail subsidiary. In connection
with the sale, we incurred indemnity obligations related to certain pre-closing
liabilities, including certain environmental matters (See Note
13B).
  PEC
  For the
three months ended March 31, 2008, including the Ward Transformer site and MGP
sites discussed below, PEC accrued approximately $1 million and spent
approximately $2 million, primarily related to the Ward Transformer site. For
the three months ended March 31, 2007, PEC reduced its accrual by approximately
$5 million, primarily related to the Ward Transformer site, and spent
approximately $1 million. PEC defers and amortizes certain environmental
remediation expenses in accordance with orders received from the NCUC and
SCPSC.
  PEC has
recorded a minimum estimated total remediation cost for all of its remaining MGP
sites based upon its historical experience with remediation of several of its
MGP sites. The maximum amount of the range for all the sites cannot be
determined at this time as one of the remaining sites is significantly larger
than the sites for which we have historical experience. Actual experience may
differ from current estimates, and it is probable that estimates will continue
to change in the future.
  42
  During
the fourth quarter of 2004, the EPA advised PEC that it had been identified as a
PRP at the Ward Transformer site located in Raleigh, N.C. The EPA offered PEC
and a number of other PRPs the opportunity to negotiate cleanup of the site and
reimbursement to the EPA for the EPA’s past expenditures in addressing
conditions at the site. Subsequently, PEC and other PRPs signed a settlement
agreement, which requires the participating PRPs to remediate the site. During
2007, the PRP agreement was amended to include an additional participating PRP,
which reduced PEC’s allocable share, and the estimated scope of work increased.
These factors resulted in a net reduction to PEC’s accrual for this site. At
December 31, 2007, PEC’s recorded liability for the site was approximately $6
million. Actual experience may differ from current estimates, and it is probable
that estimates will continue to change in the future. The outcome of this matter
cannot be predicted.
  The EPA
has also proposed, but not yet selected, a final remedial action plan to address
stream segments downstream from the Ward Transformer site. The outcome of this
matter cannot be predicted.
  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 is in the process of
examining distribution transformer sites and substation sites for mineral
oil-impacted soil remediation caused by equipment integrity issues. PEF has
reviewed a number of distribution transformer sites and all substation sites.
Based on changes to the estimated time frame for inspections of distribution
transformer sites, PEF currently expects to have completed this review by the
end of 2008. Should further sites be identified, PEF believes that any estimated
costs would also be recovered through the ECRC. For the three months ended March
31, 2008 and 2007, PEF accrued approximately $2 million due to increases in
estimated remediation costs and spent approximately $6 million and $5 million,
respectively, related to the remediation of transformers. At March 31, 2008, PEF
had recorded a regulatory asset for the probable recovery of these costs through
the ECRC.
  The
amounts for MGP and other sites, in the table above, relate to two former MGP
sites and other sites associated with PEF that have required or are anticipated
to require investigation and/or remediation. The amounts include approximately
$12 million in insurance claim settlement proceeds received in 2004, which are
restricted for use in addressing costs associated with environmental
liabilities. For the three months ended March 31, 2008 and 2007, PEF made no
additional accruals or material expenditures.
  B.
              AIR
      AND WATER QUALITY
  We are
subject to various current federal, state and local environmental compliance
laws and regulations governing air and water quality, resulting in capital
expenditures and increased O&M expenses. These compliance laws and
regulations include the Clean Air Interstate Rule (CAIR), the Clean Air
Visibility Rule (CAVR), the NOx SIP Call Rule under Section 110 of the Clean Air
Act (NOx SIP Call), the Clean Smokestacks Act and mercury regulation. PEC’s and
PEF’s environmental compliance capital expenditures related to these regulations
began in 2002 and 2005, respectively. At March 31, 2008, cumulative
environmental compliance capital expenditures to date with regard to these
environmental laws and regulations were $1.753 billion, including $1.274 billion
at PEC and $479 million at PEF. At December 31, 2007, cumulative environmental
compliance capital expenditures to date with regard to these environmental laws
and regulations were $1.567 billion, including $1.244 billion at PEC and $323
million at PEF.
  As
discussed in Note 4A, in June 2002, the Clean Smokestacks Act was enacted in
North Carolina requiring the state's electric utilities to reduce the emissions
of NOx and SO2 from their
North Carolina coal-fired power plants in phases by 2013. Two of PEC’s largest
coal-fired generating units (the Roxboro No. 4 and Mayo Units) impacted by the
Clean Smokestacks Act are jointly owned. Pursuant to joint ownership agreements,
the joint owners are required to pay a portion of the costs of owning and
operating these plants. PEC has determined that the most cost-effective Clean
Smokestacks Act compliance strategy is to maximize the SO2removal
from its larger coal-fired units, including Roxboro No. 4 and Mayo, so as to
avoid the installation of expensive emission controls on its smaller coal-fired
units. In order to address the joint owner's concerns that such a compliance
strategy would result in a disproportionate share of the cost of compliance for
the jointly owned units, PEC entered into an agreement with the joint owner to
limit its aggregate costs associated with capital expenditures to comply with
the Clean Smokestacks Act to approximately $38 million. PEC recorded a related
liability for the joint owner's share of estimated costs in
  43
  excess of
the contract amount. At March 31, 2008 and December 31, 2007, the amount of the
liability was $25 million and $30 million, respectively, based upon the
respective estimates for the remaining Clean Smokestacks Act compliance costs.
During the three months ended March 31, 2008, PEC made no additional accruals
and spent approximately $5 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. In a settlement
agreement provisionally approved by the NCUC on December 20, 2007, eligible
compliance costs in excess of the joint owner’s share will be treated in the
same manner as PEC’s Clean Smokestacks Act compliance costs in excess of the
original estimated compliance costs, as ultimately approved by the NCUC (See
Note 4A).
  13.
              COMMITMENTS AND
      CONTINGENCIES
  Contingencies
and significant changes to the commitments discussed in Note 22 in the 2007 Form
10-K are described below.
  A.
              PURCHASE
      OBLIGATION
  PROGRESS
ENERGY
  As part
of our ordinary course of business, we enter into various long- and short-term
contracts for fuel requirements at our generating plants. Through March 31,
2008, contracts procured through our subsidiaries have increased our aggregate
purchase obligations for fuel and purchased power by $4.287 billion from $17.644
billion, as stated in Note 22A in the 2007 Form 10-K. This increase is discussed
under “PEC” and “PEF” below.
  PEC
  Through
March 31, 2008, PEC’s fuel and purchase power commitments increased by $3.248
billion from $5.078 billion, as stated in Note 22A in the 2007 Form 10-K. This
increase is primarily related to coal purchase commitments, of which
approximately $2 billion will be incurred through 2012, with the remainder
incurred through 2018.
  PEF
  Through
March 31, 2008, PEF’s fuel and purchase power commitments increased by $1.039
billion from $12.566 billion as stated in Note 22A in the 2007 Form 10-K.
Approximately $640 million of this increase is due to coal purchase commitments,
of which approximately $191 million will be incurred through 2012, with the
remainder incurred through 2018. Additionally, approximately $470 million of the
increase will be incurred in the period 2014 through 2027 and is due to the
impact of rising natural gas prices under a long-term gas supply agreement that
was entered into in December 2004. Payments under this agreement are based on a
published market price index. Contractual obligations under this contract are
based on estimated future market prices.
  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, 2008, we do not believe conditions are likely for significant
performance under these guarantees. To the extent liabilities are incurred as a
result of the activities covered by the guarantees, such liabilities are
included in the accompanying Balance Sheets.
 
 At March
31, 2008, we have issued guarantees and indemnifications of and for certain
asset performance, legal, tax and environmental matters to third parties,
including indemnifications made in connection with sales of businesses, which
are within the scope of FIN 45. Related to the sales of businesses, the latest
specified notice period extends until 2013 for the majority of legal, tax and
environmental matters provided for in the indemnification provisions.
Indemnifications for the performance of assets extend to 2016. For certain
matters for which we receive timely notice, our indemnity obligations may extend
beyond the notice period. Certain indemnifications have no limitations
  44
  as to
time or maximum potential future payments. In 2005, PEC entered into an
agreement with the joint owner of certain facilities at the Mayo and Roxboro
plants to limit their aggregate costs associated with capital expenditures to
comply with the Clean Smokestacks Act and recognized a liability related to this
indemnification (See Note 12B). PEC’s maximum exposure cannot be determined. At
March 31, 2008, the estimated maximum exposure for guarantees and
indemnifications for which a maximum exposure is determinable was $458 million,
including $32 million at PEF. At March 31, 2008 and December 31, 2007, we have
recorded liabilities related to guarantees and indemnifications to third parties
of approximately $78 million and $80 million, respectively. These amounts
include $25 million and $30 million, respectively, for PEC and $8 million for
PEF at March 31, 2008, and December 31, 2007. During the three months ended
March 31, 2008, PEC made no additional accruals and spent approximately $5
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 has issued $300 million of guarantees
for certain payments of two wholly owned indirect subsidiaries. See Note 14 for
additional information.
  C. 
OTHER COMMITMENTS AND CONTINGENCIES
  SPENT
NUCLEAR FUEL MATTERS
  Pursuant
to the Nuclear Waste Policy Act of 1982, the Utilities entered into contracts
with the United States Department of Energy (DOE) under which the DOE agreed to
begin taking spent nuclear fuel by no later than January 31, 1998. All similarly
situated utilities were required to sign the same standard
contract.
 
 The DOE
failed to begin taking spent nuclear fuel by January 31, 1998. In January 2004,
the Utilities filed a complaint in the United States Court of Federal Claims
against the DOE, claiming that the DOE breached the Standard Contract for
Disposal of Spent Nuclear Fuel by failing to accept spent nuclear fuel from our
various facilities on or before January 31, 1998. Approximately 60 cases
involving the government’s actions in connection with spent nuclear fuel are
currently pending in the Court of Federal Claims. The Utilities have asserted
nearly $91 million in damages incurred between January 31, 1998 and December 31,
2005; the time period set by the court for damages in this case. The Utilities
will be free to file subsequent damages claims as they incur additional
costs.
 
 A trial
was held in November 2007, and closing arguments presented on April 4, 2008. We
expect a ruling later in 2008. The Utilities cannot predict the outcome of this
matter. 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.
  In July
2002, Congress passed an override resolution to Nevada’s veto of the DOE’s
proposal to locate a permanent underground nuclear waste storage facility at
Yucca Mountain, Nev. In January 2003, the state of Nevada; Clark County, Nev.;
and the city of Las Vegas petitioned the U.S. Court of Appeals for the District
of Columbia Circuit for review of the Congressional override resolution. These
same parties also challenged the EPA’s radiation standards for Yucca Mountain.
On July 9, 2004, the Court rejected the challenge to the constitutionality of
the resolution approving Yucca Mountain, but ruled that the EPA was wrong to set
a 10,000-year compliance period in the radiation protection standard. In August
2005, the EPA issued new proposed standards. The proposed standards include a
1,000,000-year compliance period in the radiation protection standard. Comments
were due November 21, 2005, and are being reviewed by the EPA. The DOE
originally planned to submit a license application to the NRC to construct the
Yucca Mountain facility by the end of 2004. However, in November 2004, the DOE
announced it would not submit the license application until mid-2005 or later.
The DOE did not submit the license application in 2005 and subsequently reported
that the license application would be submitted by June 2008 if full funding was
obtained for the project. The DOE requested $545 million for fiscal year 2007
and received $445 million. The DOE requested $495 million for fiscal year 2008.
However, Congress passed an appropriations bill which allocates $390 million in
fiscal year 2008 for DOE’s Yucca Mountain repository program. Despite the cuts
in requested funding, the DOE is expected to submit the license application by
the end of June 2008.
  On
October 19, 2007, the DOE certified the regulatory compliance of the document
database that will be used by all parties involved in the federal licensing
process for the Yucca Mountain facility. The NRC did not uphold the DOE’s prior
certification in 2004 in response to challenges from the state of Nevada. The
state again is expected to
  45
  challenge
the DOE’s certification process. The DOE has stated that if legislative changes
requested by the Bush administration are enacted, the repository may be able to
accept spent nuclear fuel starting in 2017, but 2020 is more likely due to
anticipated litigation by the state of Nevada. The Utilities cannot predict the
outcome of this matter.
  With
certain modifications and additional approvals by the NRC, including the
installation of on-site dry cask storage facilities at PEC’s Robinson Nuclear
Plant, PEC’s Brunswick Nuclear Plant and CR3, the Utilities’ spent nuclear fuel
storage facilities will be sufficient to provide storage space for spent fuel
generated on their respective systems through the expiration of the operating
licenses, including any license extensions, for their nuclear generating units.
PEC’s Shearon Harris Nuclear Plant (Harris) has sufficient storage capacity in
its spent fuel pools through the expiration of its operating license, including
any license extensions.
  SYNTHETIC
FUELS MATTERS
  A number
of our subsidiaries and affiliates are parties to two lawsuits arising out of an
Asset Purchase Agreement dated as of October 19, 1999, by and among U.S. Global,
LLC (Global); the Earthco synthetic fuels facilities (Earthco); certain
affiliates of Earthco; EFC Synfuel LLC (which is owned indirectly by Progress
Energy, Inc.) and certain of its affiliates, including Solid Energy LLC; Solid
Fuel LLC; Ceredo Synfuel LLC; Gulf Coast Synfuel LLC (currently named Sandy
River Synfuel LLC) (collectively, the Progress Affiliates), as amended by an
amendment to Purchase Agreement as of August 23, 2000 (the Asset Purchase
Agreement). Global has asserted (1) that pursuant to the Asset Purchase
Agreement, it is entitled to an interest in two synthetic fuels facilities
currently owned by the Progress Affiliates and an option to purchase additional
interests in the two synthetic fuels facilities, (2) that it is entitled to
damages because the Progress Affiliates prohibited it from procuring purchasers
for the synthetic fuels facilities and (3) a number of tort claims related to
the contracts.
  The first
suit, U.S. Global, LLC v.
Progress Energy, Inc. et al. (the Florida Global Case), asserts the above
claims in a case filed in the Circuit Court for Broward County, Fla., in March
2003, and requests an unspecified amount of compensatory damages, as well as
declaratory relief. The Progress Affiliates have answered the Complaint by
generally denying all of Global’s substantive allegations and asserting numerous
substantial affirmative defenses. The case is at issue, but neither party has
requested a trial. The parties are currently engaged in discovery in the Florida
Global Case.
  The
second suit, Progress Synfuel
Holdings, Inc. et al. v. U.S. Global, LLC (the North Carolina Global
Case), was filed by the Progress Affiliates in the Superior Court for Wake
County, N.C., seeking declaratory relief consistent with our interpretation of
the Asset Purchase Agreement. Global was served with the North Carolina Global
Case on April 17, 2003.
  On May
15, 2003, Global moved to dismiss the North Carolina Global Case for lack of
personal jurisdiction over Global. In the alternative, Global requested that the
court decline to exercise its discretion to hear the Progress Affiliates’
declaratory judgment action. On August 7, 2003, the Wake County Superior Court
denied Global’s motion to dismiss, but stayed the North Carolina Global Case,
pending the outcome of the Florida Global Case. The Progress Affiliates appealed
the superior court’s order staying the case. By order dated September 7, 2004,
the North Carolina Court of Appeals dismissed the Progress Affiliates’ appeal.
Since that time, the parties have been engaged in discovery in the Florida
Global Case.
  In
December 2006, we reached agreement with Global to settle an additional claim in
the suit related to amounts due to Global that were placed in escrow pursuant to
a defined tax event. Upon the successful resolution of the IRS audit of the
Earthco synthetic fuels facilities in 2006, and pursuant to a settlement
agreement, the escrow totaling $42 million as of December 31, 2006, was paid to
Global in January 2007.
  In
January 2008, Global agreed to simplify the Florida action by dismissing the
tort claims. The Florida Global Case continues now under contract theories
alone. The case is scheduled to go to trial in April 2009. We cannot predict the
outcome of this matter.
  OTHER
LITIGATION MATTERS
  We and
our subsidiaries are involved in various litigation matters in the ordinary
course of business, some of which involve substantial amounts. Where
appropriate, we have made accruals and disclosures in accordance with SFAS No. 5
"Accounting for Contingencies" to provide for such matters. In the opinion of
management, the final
  46
 disposition
of pending litigation would not have a material adverse effect on our
consolidated results of operations or financial position.
 
 14.
              CONDENSED
      CONSOLIDATING STATEMENTS
  As
discussed in Note 23 in the 2007 Form 10-K, we have guaranteed certain payments
of two wholly owned indirect subsidiaries, FPC Capital I (the Trust) and Florida
Progress Funding Corporation (Funding Corp.) since September 2005. Our
guarantees are joint and several, full and unconditional and are in addition to
the joint and several, full and unconditional guarantees previously issued to
the Trust and Funding Corp. by Florida Progress. Our subsidiaries have
provisions restricting the payment of dividends to the Parent in certain limited
circumstances and as disclosed in Note 12B in the 2007 Form 10-K, there were no
restrictions on PEC’s or PEF’s retained earnings.
  The Trust
is a special-purpose entity and was deconsolidated in 2003 in accordance with
the provisions of FIN 46R. The deconsolidation was not material to our financial
statements. Separate financial statements and other disclosures concerning the
Trust have not been presented because we believe that such information is not
material to investors.
  Presented
below are the condensed consolidating Statements of Income, Balance Sheets and
Cash Flows as required by Rule 3-10 of Regulation S-X. In these condensed
consolidating statements, the Parent column includes the financial results of
the parent holding company only. The Subsidiary Guarantor column includes the
consolidated financial results of Florida Progress only, which is primarily
comprised of its wholly owned subsidiary PEF. The Other column includes the
consolidated financial results of all other non-guarantor
subsidiaries, primarily our wholly owned subsidiary PEC,  and
elimination entries for all intercompany transactions. Financial statements for
PEC and PEF are separately presented elsewhere in this Form 10-Q. All applicable
corporate expenses have been allocated appropriately among the guarantor and
non-guarantor subsidiaries. The financial information may not necessarily be
indicative of results of operations or financial position had the Subsidiary
Guarantor or other non-guarantor subsidiaries operated as independent entities.
The accompanying condensed consolidating financial statements have been restated
for all periods presented to reflect the operations of Terminals and the
synthetic fuels businesses as discontinued operations as described in Note
3A.
  47
 
 Condensed
      Consolidating Statement of Income
                Three
      months ended March 31, 2008(in
      millions)
              
              Parent
              
              
              Subsidiary
                Guarantor
              
              
              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
              
              
              
              240
              
              
              
              443Depreciation
      and amortization
              
              
              –
              
              
              
              76
              
              
              
              130
              
              
              
              206Taxes
      other than on income
              
              
              –
              
              
              
              71
              
              
              
              50
              
              
              
              121Other
              
              
              –
              
              
              
              2
              
              
              
              –
              
              
              
              2Total
      operating expenses
              
              
              –
              
              
              
              876
              
              
              
              825
              
              
              
              1,701Operating
      income
              
              
              –
              
              
              
              122
              
              
              
              243
              
              
              
              365Other
      income, net
              
              
              4
              
              
              
              15
              
              
              
              6
              
              
              
              25Interest
      charges, net
              
              
              48
              
              
              
              51
              
              
              
              54
              
              
              
              153(Loss)
      income from continuing operations before income tax, equity in
                earnings
      ofconsolidated
      subsidiaries and minority interest
              
              
              (44
              )
              
              
              86
              
              
              
              195
              
              
              
              237Income
      tax (benefit) expense
              
              
              (18
              )
              
              
              27
              
              
              
              75
              
              
              
              84Equity
      in earnings of consolidated subsidiaries
              
              
              235
              
              
              
              –
              
              
              
              (235
              )
              
              
              –Minority
      interest in subsidiaries’ income, net of tax
              
              
              –
              
              
              
              (4
              )
              
              
              –
              
              
              
              (4
              )Income
      (loss) from continuing operations
              
              
              209
              
              
              
              55
              
              
              
              (115
              )
              
              
              149Discontinued
      operations, net of tax
              
              
              –
              
              
              
              56
              
              
              
              4
              
              
              
              60Net
      income (loss)
              
              $
              209
              
              
              $
              111
              
              
              $
              (111
              )
              
              $
              209
 
  48
  
 Condensed
      Consolidating Statement of Income
                Three
      months ended March 31, 2007(in
      millions)
              
              Parent
              
              
              Subsidiary
                Guarantor
              
              
              Other
              
              
              Progress
                Energy,
      Inc.Operating
      revenues
              
              $
              –
              
              
              $
              1,014
              
              
              $
              1,058
              
              
              $
              2,072Operating
      expensesFuel
      used in electric generation
              
              
              –
              
              
              
              385
              
              
              
              351
              
              
              
              736Purchased
      power
              
              
              –
              
              
              
              163
              
              
              
              58
              
              
              
              221Operation
      and maintenance
              
              
              5
              
              
              
              175
              
              
              
              240
              
              
              
              420Depreciation
      and amortization
              
              
              –
              
              
              
              97
              
              
              
              122
              
              
              
              219Taxes
      other than on income
              
              
              –
              
              
              
              74
              
              
              
              50
              
              
              
              124Other
              
              
              –
              
              
              
              (1
              )
              
              
              2
              
              
              
              1Total
      operating expenses
              
              
              5
              
              
              
              893
              
              
              
              823
              
              
              
              1,721Operating
      (loss) income
              
              
              (5
              )
              
              
              121
              
              
              
              235
              
              
              
              351Other
      income, net
              
              
              6
              
              
              
              8
              
              
              
              5
              
              
              
              19Interest
      charges, net
              
              
              49
              
              
              
              44
              
              
              
              49
              
              
              
              142(Loss)
      income from continuing operations before income tax, equity in
                earnings
      ofconsolidated
      subsidiaries and minority interest
              
              
              (48
              )
              
              
              85
              
              
              
              191
              
              
              
              228Income
      tax (benefit) expense
              
              
              (20
              )
              
              
              25
              
              
              
              67
              
              
              
              72Equity
      in earnings of consolidated subsidiaries
              
              
              302
              
              
              
              –
              
              
              
              (302
              )
              
              
              –Minority
      interest in subsidiaries’ income, net of tax
              
              
              –
              
              
              
              (7
              )
              
              
              –
              
              
              
              (7
              )Income
      (loss) from continuing operations
              
              
              274
              
              
              
              53
              
              
              
              (178
              )
              
              
              149Discontinued
      operations, net of tax
              
              
              1
              
              
              
              29
              
              
              
              96
              
              
              
              126Net
      income (loss)
              
              $
              275
              
              
              $
              82
              
              
              $
              (82
              )
              
              $
              275
 
  49
  
 Condensed
      Consolidating Balance Sheet
                March
      31, 2008(in
      millions)
              
              Parent
              
              
              Subsidiary
                Guarantor
              
              
              Other
              
              
              Progress
                Energy,
      Inc.Utility
      plant, net
              
              $
              –
              
              
              $
              7,921
              
              
              $
              9,065
              
              
              $
              16,986Current
      assetsCash
      and cash equivalents
              
              
              19
              
              
              
              83
              
              
              
              298
              
              
              
              400Receivables,
      net
              
              
              –
              
              
              
              313
              
              
              
              454
              
              
              
              767Notes
      receivable from affiliated companies
              
              
              35
              
              
              
              38
              
              
              
              (73
              )
              
              
              –Derivative
      assets
              
              
              –
              
              
              
              204
              
              
              
              13
              
              
              
              217Prepayments
      and other current assets
              
              
              37
              
              
              
              525
              
              
              
              652
              
              
              
              1,214Total
      current assets
              
              
              91
              
              
              
              1,163
              
              
              
              1,344
              
              
              
              2,598Deferred
      debits and other assetsInvestment
      in consolidated subsidiaries
              
              
              11,325
              
              
              
              –
              
              
              
              (11,325
              )
              
              
              –Goodwill
              
              
              –
              
              
              
              –
              
              
              
              3,655
              
              
              
              3,655Derivative
      assets
              
              
              –
              
              
              
              174
              
              
              
              36
              
              
              
              210Other
      assets and deferred debits
              
              
              147
              
              
              
              1,507
              
              
              
              1,441
              
              
              
              3,095Total
      deferred debits and other assets
              
              
              11,472
              
              
              
              1,681
              
              
              
              (6,193
              )
              
              
              6,960Total
      assets
              
              $
              11,563
              
              
              $
              10,765
              
              
              $
              4,216
              
              
              $
              26,544CapitalizationCommon
      stock equity
              
              $
              8,518
              
              
              $
              3,243
              
              
              $
              (3,243
              )
              
              $
              8,518Preferred
      stock of subsidiaries – not subject to mandatory
redemption
              
              
              –
              
              
              
              34
              
              
              
              59
              
              
              
              93Minority
      interest
              
              
              –
              
              
              
              2
              
              
              
              4
              
              
              
              6Long-term
      debt, affiliate
              
              
              –
              
              
              
              309
              
              
              
              (38
              )
              
              
              271Long-term
      debt, net
              
              
              2,597
              
              
              
              2,687
              
              
              
              3,107
              
              
              
              8,391Total
      capitalization
              
              
              11,115
              
              
              
              6,275
              
              
              
              (111
              )
              
              
              17,279Current
      liabilitiesCurrent
      portion of long-term debt
              
              
              –
              
              
              
              497
              
              
              
              700
              
              
              
              1,197Notes
      payable to affiliated companies
              
              
              –
              
              
              
              175
              
              
              
              (175
              )
              
              
              –Other
      current liabilities
              
              
              404
              
              
              
              1,156
              
              
              
              629
              
              
              
              2,189Total
      current liabilities
              
              
              404
              
              
              
              1,828
              
              
              
              1,154
              
              
              
              3,386Deferred
      credits and other liabilitiesNoncurrent
      income tax liabilities
              
              
              –
              
              
              
              51
              
              
              
              237
              
              
              
              288Regulatory
      liabilities
              
              
              –
              
              
              
              1,544
              
              
              
              1,231
              
              
              
              2,775Other
      liabilities and deferred credits
              
              
              44
              
              
              
              1,067
              
              
              
              1,705
              
              
              
              2,816Total
      deferred credits and other liabilities
              
              
              44
              
              
              
              2,662
              
              
              
              3,173
              
              
              
              5,879Total
      capitalization and liabilities
              
              $
              11,563
              
              
              $
              10,765
              
              
              $
              4,216
              
              
              $
              26,544
 
  50
  
 Condensed
      Consolidating Balance Sheet
                December
      31, 2007(in
      millions)
              
              Parent
              
              
              Subsidiary
                Guarantor
              
              
              Other
              
              
              Progress
                Energy,
      Inc.Utility
      plant, net
              
              $
              –
              
              
              $
              7,600
              
              
              $
              9,005
              
              
              $
              16,605Current
      assetsCash
      and cash equivalents
              
              
              185
              
              
              
              43
              
              
              
              27
              
              
              
              255Receivables,
      net
              
              
              –
              
              
              
              574
              
              
              
              593
              
              
              
              1,167Notes
      receivable from affiliated companies
              
              
              157
              
              
              
              149
              
              
              
              (306
              )
              
              
              –Derivative
      assets
              
              
              –
              
              
              
              83
              
              
              
              2
              
              
              
              85Assets
      to be divested
              
              
              –
              
              
              
              48
              
              
              
              4
              
              
              
              52Prepayments
      and other current assets
              
              
              21
              
              
              
              595
              
              
              
              654
              
              
              
              1,270Total
      current assets
              
              
              363
              
              
              
              1,492
              
              
              
              974
              
              
              
              2,829Deferred
      debits and other assetsInvestment
      in consolidated subsidiaries
              
              
              10,969
              
              
              
              –
              
              
              
              (10,969
              )
              
              
              –Goodwill
              
              
              –
              
              
              
              1
              
              
              
              3,654
              
              
              
              3,655Derivative
      assets
              
              
              –
              
              
              
              100
              
              
              
              19
              
              
              
              119Other
      assets and deferred debits
              
              
              149
              
              
              
              1,475
              
              
              
              1,533
              
              
              
              3,157Total
      deferred debits and other assets
              
              
              11,118
              
              
              
              1,576
              
              
              
              (5,763
              )
              
              
              6,931Total
      assets
              
              $
              11,481
              
              
              $
              10,668
              
              
              $
              4,216
              
              
              $
              26,365CapitalizationCommon
      stock equity
              
              $
              8,422
              
              
              $
              3,052
              
              
              $
              (3,052
              )
              
              $
              8,422Preferred
      stock of subsidiaries – not subject to mandatory
redemption
              
              
              –
              
              
              
              34
              
              
              
              59
              
              
              
              93Minority
      interest
              
              
              –
              
              
              
              81
              
              
              
              3
              
              
              
              84Long-term
      debt, affiliate
              
              
              –
              
              
              
              309
              
              
              
              (38
              )
              
              
              271Long-term
      debt, net
              
              
              2,597
              
              
              
              2,686
              
              
              
              3,183
              
              
              
              8,466Total
      capitalization
              
              
              11,019
              
              
              
              6,162
              
              
              
              155
              
              
              
              17,336Current
      liabilitiesCurrent
      portion of long-term debt
              
              
              –
              
              
              
              577
              
              
              
              300
              
              
              
              877Notes
      payable to affiliated companies
              
              
              –
              
              
              
              227
              
              
              
              (227
              )
              
              
              –Liabilities
      to be divested
              
              
              –
              
              
              
              8
              
              
              
              –
              
              
              
              8Other
      current liabilities
              
              
              416
              
              
              
              1,237
              
              
              
              764
              
              
              
              2,417Total
      current liabilities
              
              
              416
              
              
              
              2,049
              
              
              
              837
              
              
              
              3,302Deferred
      credits and other liabilitiesNoncurrent
      income tax liabilities
              
              
              –
              
              
              
              59
              
              
              
              302
              
              
              
              361Regulatory
      liabilities
              
              
              –
              
              
              
              1,330
              
              
              
              1,224
              
              
              
              2,554Other
      liabilities and deferred credits
              
              
              46
              
              
              
              1,068
              
              
              
              1,698
              
              
              
              2,812Total
      deferred credits and other liabilities
              
              
              46
              
              
              
              2,457
              
              
              
              3,224
              
              
              
              5,727Total
      capitalization and liabilities
              
              $
              11,481
              
              
              $
              10,668
              
              
              $
              4,216
              
              
              $
              26,365
 
  51
  
 Condensed
      Consolidating Statement of Cash Flows
                Three
      months ended March 31, 2008(in
      millions)
              
              Parent
              
              
              Subsidiary
                Guarantor
              
              
              Other
              
              
              Progress
                Energy,
      Inc.Net
      cash (used) provided by operating activities
              
              $
              (55
              )
              
              $
              393
              
              
              $
              439
              
              
              $
              777Investing
      activitiesGross
      property additions
              
              
              –
              
              
              
              (446
              )
              
              
              (172
              )
              
              
              (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
              )
              
              
              (241
              )
              
              
              (488
              )Proceeds
      from sales of available-for-sale securities and other
      investments
              
              
              –
              
              
              
              247
              
              
              
              226
              
              
              
              473Changes
      in advances to affiliates
              
              
              122
              
              
              
              111
              
              
              
              (233
              )
              
              
              –Other
      investing activities
              
              
              (97
              )
              
              
              14
              
              
              
              77
              
              
              
              (6
              )Net
      cash provided (used) by investing activities
              
              
              25
              
              
              
              (219
              )
              
              
              (391
              )
              
              
              (585
              )Financing
      activitiesIssuance
      of common stock
              
              
              20
              
              
              
              –
              
              
              
              –
              
              
              
              20Dividends
      paid on common stock
              
              
              (159
              )
              
              
              –
              
              
              
              –
              
              
              
              (159
              )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, net
              
              
              –
              
              
              
              –
              
              
              
              322
              
              
              
              322Retirement
      of long-term debt
              
              
              –
              
              
              
              (80
              )
              
              
              –
              
              
              
              (80
              )Cash
      distributions to minority interests of consolidated
      subsidiaries
              
              
              –
              
              
              
              (85
              )
              
              
              –
              
              
              
              (85
              )Dividends
      paid to parent
              
              
              –
              
              
              
              (3
              )
              
              
              3
              
              
              
              –Changes
      in advances from affiliates
              
              
              –
              
              
              
              (53
              )
              
              
              53
              
              
              
              –Other
      financing activities
              
              
              (1
              )
              
              
              87
              
              
              
              (155
              )
              
              
              (69
              )Net
      cash (used) provided by financing activities
              
              
              (136
              )
              
              
              (134
              )
              
              
              223
              
              
              
              (47
              )Net
      (decrease) increase in cash and cash equivalents
              
              
              (166
              )
              
              
              40
              
              
              
              271
              
              
              
              145Cash
      and cash equivalents at beginning of period
              
              
              185
              
              
              
              43
              
              
              
              27
              
              
              
              255Cash
      and cash equivalents at end of period
              
              $
              19
              
              
              $
              83
              
              
              $
              298
              
              
              $
              400
 
  52
  
 Condensed
      Consolidating Statement of Cash Flows
                Three
      months ended March 31, 2007(in
      millions)
              
              Parent
              
              
              Subsidiary
                Guarantor
              
              
              Other
              
              
              Progress
                Energy,
      Inc.Net
      cash (used) provided by operating activities
              
              $
              (8
              )
              
              $
              31
              
              
              $
              293
              
              
              $
              316Investing
      activitiesGross
      property additions
              
              
              –
              
              
              
              (262
              )
              
              
              (209
              )
              
              
              (471
              )Nuclear
      fuel additions
              
              
              –
              
              
              
              (23
              )
              
              
              (38
              )
              
              
              (61
              )Proceeds
      from sales of discontinued operations and other assets, net of cash
      divested
              
              
              –
              
              
              
              25
              
              
              
              5
              
              
              
              30Purchases
      of available-for-sale securities and other investments
              
              
              –
              
              
              
              (44
              )
              
              
              (148
              )
              
              
              (192
              )Proceeds
      from sales of available-for-sale securities and other
      investments
              
              
              21
              
              
              
              44
              
              
              
              187
              
              
              
              252Changes
      in advances to affiliates
              
              
              (180
              )
              
              
              37
              
              
              
              143
              
              
              
              –Other
      investing activities
              
              
              (2
              )
              
              
              (5
              )
              
              
              7
              
              
              
              –Net
      cash used by investing activities
              
              
              (161
              )
              
              
              (228
              )
              
              
              (53
              )
              
              
              (442
              )Financing
      activitiesIssuance
      of common stock
              
              
              65
              
              
              
              –
              
              
              
              –
              
              
              
              65Dividends
      paid on common stock
              
              
              (155
              )
              
              
              –
              
              
              
              –
              
              
              
              (155
              )Net
      increase in short-term debt
              
              
              117
              
              
              
              –
              
              
              
              –
              
              
              
              117Changes
      in advances from affiliates
              
              
              –
              
              
              
              187
              
              
              
              (187
              )
              
              
              –Other
      financing activities
              
              
              (1
              )
              
              
              11
              
              
              
              (43
              )
              
              
              (33
              )Net
      cash provided (used) by financing activities
              
              
              26
              
              
              
              198
              
              
              
              (230
              )
              
              
              (6
              )Net
      (decrease) increase in cash and cash equivalents
              
              
              (143
              )
              
              
              1
              
              
              
              10
              
              
              
              (132
              )Cash
      and cash equivalents at beginning of period
              
              
              153
              
              
              
              40
              
              
              
              72
              
              
              
              265Cash
      and cash equivalents at end of period
              
              $
              10
              
              
              $
              41
              
              
              $
              82
              
              
              $
              133
 
  53
  ITEM
2.                  MANAGEMENT’S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
  The
following combined Management’s Discussion and Analysis of Financial Condition
and Results of Operations (MD&A) is separately filed by Progress Energy,
Inc. (Progress Energy), Carolina Power & Light Company d/b/a Progress Energy
Carolinas, Inc. (PEC) and Florida Power Corporation d/b/a Progress Energy
Florida, Inc. (PEF). As used in this report, Progress Energy, which includes
Progress Energy, Inc. holding company (the Parent) and its regulated and
nonregulated subsidiaries on a consolidated basis, is at times referred to as
“we,” “us” or “our.” When discussing Progress Energy’s financial information, it
necessarily includes the results of PEC and PEF (collectively, the Utilities).
The term “Progress Registrants” refers to each of the three separate
registrants: Progress Energy, PEC and PEF. Information contained herein relating
to PEC and PEF individually is filed by such company on its own behalf. Neither
of the Utilities makes any representation as to information related solely to
Progress Energy or the subsidiaries of Progress Energy other than
itself.
  The
following MD&A contains forward-looking statements that involve estimates,
projections, goals, forecasts, assumptions, risks and uncertainties that could
cause actual results or outcomes to differ materially from those expressed in
the forward-looking statements. Please review “Safe Harbor for Forward-Looking
Statements” and Item 1A, “Risk Factors” found within Part II of this Form 10-Q
and Item 1A, “Risk Factors” to the Progress Registrant’s annual report on Form
10-K for the fiscal year ended December 31, 2007 (2007 Form 10-K) for a
discussion of the factors that may impact any such forward-looking statements
made herein.
  Amounts
reported in the interim statements of income are not necessarily indicative of
amounts expected for the respective annual or future periods due to the effects
of weather variations and the timing of outages of electric generating units,
especially nuclear-fueled units, among other factors.
  This
discussion should be read in conjunction with the accompanying financial
statements found elsewhere in this report and in conjunction with the 2007 Form
10-K.
  PROGRESS
ENERGY
  RESULTS OF
OPERATIONS
  Our
reportable operating business segments are PEC and PEF, which are primarily
engaged in the generation, transmission, distribution and sale of electricity in
portions of North Carolina and South Carolina, and Florida,
respectively.
  Our
“Corporate and Other” segment primarily includes the operations of the Parent,
Progress Energy Service Company, LLC (PESC) and other miscellaneous nonregulated
businesses that do not separately meet the quantitative disclosure requirements
as a separate business segment.
  As
discussed more fully in Note 3 and “Results of Operations – Discontinued
Operations,” in accordance with our business strategy to reduce our business
risk and to focus on the core operations of the Utilities, the majority of our
nonregulated business operations have been divested. These operations have been
classified as discontinued operations in the accompanying financial statements.
Consequently, the composition of other continuing segments has been impacted by
these divestitures. For comparative purposes, prior year results have been
restated to conform to the current presentation. In this section, earnings and
the factors affecting earnings for the three months ended March 31, 2008, are
compared to the same period in 2007. The discussion begins with a summarized
overview of our consolidated earnings, which is followed by a more detailed
discussion and analysis by business segment.
  54
  OVERVIEW
  For the
quarter ended March 31, 2008, our net income was $209 million, or $0.81 per
share, compared to net income of $275 million, or $1.08 per share, for the same
period in 2007. For each of the quarters ended March 31, 2008 and 2007, our
income from continuing operations was $149 million. Our income from continuing
operations as compared to prior year was positively impacted by:
  ·
              favorable
      allowance for funds used during construction (AFUDC) equity at
      PEF;
 ·
              favorable
      retail customer growth and usage at
PEC;
 ·
              increased
      retail rates at PEF;
 ·
              lower
      purchased power expense at PEC due to the expiration of a power buyback
      agreement; and
 ·
              higher
      wholesale revenues at PEF.
 
 Offsetting
these items were:
  ·
              lower
      wholesale revenues at PEC;
 ·
              higher
      depreciation and amortization expense excluding prior year recoverable
      storm amortization at the
Utilities;
 ·
              higher
      interest expense at PEF due to higher average debt
      outstanding;
  ·
              unfavorable
      retail customer growth and usage at PEF;
and
 ·
              unfavorable
      weather at PEC.
 
 Our
segments contributed the following profits or losses for the three months ended
March 31, 2008 and 2007:
  Three
      Months Ended March 31,(in
      millions)
              
              2008
              
              
              2007Business
      SegmentPEC
              
              $
              122
              
              
              $
              123PEF
              
              
              66
              
              
              
              60Total
      segment profit
              
              
              188
              
              
              
              183Corporate
      and Other
              
              
              (39
              )
              
              
              (34
              )Income
      from continuing operations
              
              
              149
              
              
              
              149Discontinued
      operations, net of tax
              
              
              60
              
              
              
              126Net
      income
              
              $
              209
              
              
              $
              275
 
 PROGRESS
ENERGY CAROLINAS
  PEC
contributed segment profits of $122 million and $123 million for the three
months ended March 31, 2008 and 2007, respectively. The decrease in profits for
the three months ended March 31, 2008, compared to the same period in 2007, was
primarily due to lower wholesale revenues, higher North Carolina Clean
Smokestacks Act (Clean Smokestacks Act) amortization and the unfavorable impact
of weather, partially offset by the favorable impact of retail customer growth
and usage and lower purchased power expense due to the expiration of a power
buyback agreement.
  The
revenue table below presents the total amount and percentage change of revenues
excluding fuel. Revenues excluding fuel is defined as total electric revenues
less fuel revenues. We and PEC consider revenues excluding fuel a useful measure
to evaluate PEC’s electric operations because fuel revenues primarily represent
the recovery of fuel and a portion of purchased power expenses through
cost-recovery clauses and, therefore, do not have a material impact on earnings.
We and PEC have included the analysis below as a complement to the financial
information we provide in accordance with accounting principles generally
accepted in the United States of America (GAAP). However, revenues excluding
fuel is not defined under GAAP, and the presentation may not be comparable to
other companies’ presentation or more useful than the GAAP information provided
elsewhere in this report.
  55
  REVENUES
  PEC’s
electric revenues for the three months ended March 31, 2008 and 2007, and the
amount and percentage change by customer class were as follows:
  (in
      millions)
              
              Three
      Months Ended March 31,Customer
      Class
              
              2008
              
              
              Change
              
              
              %
      Change
              
              
              2007Residential
              
              $
              426
              
              
              $
              2
              
              
              
              0.5
              
              
              $
              424Commercial
              
              
              262
              
              
              
              8
              
              
              
              3.1
              
              
              
              254Industrial
              
              
              168
              
              
              
              3
              
              
              
              1.8
              
              
              
              165Governmental
              
              
              23
              
              
              
              1
              
              
              
              4.5
              
              
              
              22Total
      retail revenues
              
              
              879
              
              
              
              14
              
              
              
              1.6
              
              
              
              865Wholesale
              
              
              181
              
              
              
              (13
              )
              
              
              (6.7
              )
              
              
              194Unbilled
              
              
              (17
              )
              
              
              8
              
              
              
              –
              
              
              
              (25
              )Miscellaneous
              
              
              24
              
              
              
              1
              
              
              
              4.3
              
              
              
              23Total
      electric revenues
              
              
              1,067
              
              
              
              10
              
              
              
              0.9
              
              
              
              1,057Less:
      Fuel revenues
              
              
              (390
              )
              
              
              (15
              )
              
              
              –
              
              
              
              (375
              )Revenues
      excluding fuel
              
              $
              677
              
              
              $
              (5
              )
              
              
              (0.7
              )
              
              $
              682
 
 PEC’s
electric energy sales for the three months ended March 31, 2008 and 2007, and
the amount and percentage change by customer class were as follows:
  (in
      millions of kWh)
              Three
      Months Ended March 31,Customer
      Class
              2008
              Change
              %
      Change
              2007Residential
              4,678
              (62)
              (1.3)
              4,740Commercial
              3,278
              33
              1.0
              3,245Industrial
              2,772
              (49)
              (1.7)
              2,821Governmental
              333
              6
              1.8
              327Total
      retail energy sales
              11,061
              (72)
              (0.6)
              11,133Wholesale
              3,772
              (184)
              (4.7)
              3,956Unbilled
              (241)
              102
              –
              (343)Total
      kWh sales
              14,592
              (154)
              (1.0)
              14,746
 
 PEC’s
revenues, excluding fuel revenues of $390 million and $375 million for the three
months ended March 31, 2008 and 2007, respectively, decreased $5 million. The
decrease in revenues excluding fuel is primarily due to $15 million lower
wholesale revenues and the $6 million unfavorable impact of weather, partially
offset by the $14 million favorable impact of retail customer growth and usage.
Lower wholesale revenues excluding fuel are primarily due to $12 million lower
excess generation revenues driven by unfavorable market conditions in 2008
compared to 2007 resulting from higher fuel costs. The unfavorable impact of
weather was equally driven by heating andcooling
degree dayslower than 2007. Both heating and cooling degree days
were also lower than normal. Favorable
retail customer growth and usage was driven by a 26,000 customer increase in
PEC's average net number of customers for the three months endedMarch 31,
2008,
compared to the same period in 2007, and by an increase in the average usage per
retail customer.
  Total
retail revenues increased for the three months ended March 31, 2008, despite a
decrease in total retail energy sales for the same period primarily due to the
impact of increased fuel revenues as a result of higher energy costs and the
recovery of prior year fuel costs.
  The
decline in general economic conditions, including weakness in the housing
markets in both Florida and the United States, has contributed to a slowdown in
customer growth and usage in PEF's service territory (See "Progress Energy
Florida - Revenues"). PEC has not been as significantly impacted by the decline
in general economic conditions as PEF.
  56
  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 $405 million for the three months ended March 31,
2008, which represents a $4 million decrease compared to the same period in
2007. Current year purchased power costs were $9 million lower than the three
months ended March 31, 2007, primarily due to the expiration of a power buyback
agreement with North Carolina Eastern Municipal Power Agency (Power Agency).
Additionally, deferred fuel expense decreased $11 million due to the
implementation of the North Carolina comprehensive energy legislation. The
decrease in deferred fuel expense was partially offset by an increase of $10
million due to the collection in the current year of prior years’
under-recovery.
  Depreciation and
Amortization
  Depreciation
and amortization expense was $126 million for the three months ended March 31,
2008, which represents a $9 million increase compared to the same period in
2007. Depreciation and amortization expense increased primarily due to $7
million higher Clean Smokestacks Act amortization and the impact of depreciable
asset base increases.
  Income Tax
Expense
  Income
tax expense increased $6 million for the three months ended March 31, 2008, as
compared to the same period in 2007, primarily due to $4 million prior year
changes in tax estimates, the $3 million unfavorable tax impact of employee
benefits and the $2 million tax impact of higher pre-tax earnings,
partially offset by the $2 million impact of tax levelization. GAAP requires
companies to apply a levelized effective tax rate to interim periods that is
consistent with the estimated annual effective tax rate. PEC’s income tax
expense was decreased by $3 million for the three months ended March 31, 2008
compared to a decrease of $1 million for the three months ended March 31, 2007,
in order to maintain an effective tax rate consistent with the estimated annual
rate. Fluctuations in estimated annual earnings and the timing of various
permanent items of income or deduction can cause fluctuations in the effective
tax rate for interim periods. Therefore, this adjustment will vary each quarter,
but will have no effect on net income for the year.
  PROGRESS
ENERGY FLORIDA
  PEF
contributed segment profits of $66 million and $60 million for the three months
ended March 31, 2008 and 2007, respectively. The increase in profits for the
three months ended March 31, 2008, compared to the same period in 2007, was
primarily due to favorable AFUDC, an increase in retail rates and higher
wholesale revenues, partially offset by higher interest charges, the unfavorable
impact of retail customer growth and usage and higher depreciation and
amortization expense excluding prior year recoverable storm
amortization.
  The
revenue table below 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.
   57
  REVENUES
  PEF’s
electric revenues for the three months ended March 31, 2008 and 2007, and the
amount and percentage change by customer class were as follows:
  (in
      millions)
              
              Three
      Months Ended March 31,Customer
      Class
              
              2008
              
              
              Change
              
              
              %
      Change
              
              
              2007Residential
              
              $
              464
              
              
              $
              (27
              )
              
              
              (5.5
              )
              
              $
              491Commercial
              
              
              242
              
              
              
              (5
              )
              
              
              (2.0
              )
              
              
              247Industrial
              
              
              69
              
              
              
              (5
              )
              
              
              (6.8
              )
              
              
              74Governmental
              
              
              67
              
              
              
              –
              
              
              
              –
              
              
              
              67Total
      retail revenues
              
              
              842
              
              
              
              (37
              )
              
              
              (4.2
              )
              
              
              879Wholesale
              
              
              103
              
              
              
              23
              
              
              
              28.8
              
              
              
              80Unbilled
              
              
              6
              
              
              
              (2
              )
              
              
              –
              
              
              
              8Miscellaneous
              
              
              45
              
              
              
              1
              
              
              
              2.3
              
              
              
              44Total
      electric revenues
              
              
              996
              
              
              
              (15
              )
              
              
              (1.5
              )
              
              
              1,011Less:
      Fuel and other pass-through revenues
              
              
              (608
              )
              
              
              37
              
              
              
              –
              
              
              
              (645
              )Revenues
      excluding fuel and other pass-through revenues
              
              $
              388
              
              
              $
              22
              
              
              
              6.0
              
              
              $
              366
 
 PEF’s
electric energy sales for the three months ended March 31, 2008 and 2007, and
the amount and percentage change by customer class are as follows:
  (in
      millions of kWh)
              Three
      Months Ended March 31,Customer
      Class
              2008
              Change
              %
      Change
              2007Residential
              4,005
              (150)
              (3.6)
              4,155Commercial
              2,661
              37
              1.4
              2,624Industrial
              865
              (30)
              (3.4)
              895Governmental
              767
              19
              2.5
              748Total
      retail energy sales
              8,298
              (124)
              (1.5)
              8,422Wholesale
              1,390
              220
              18.8
              1,170Unbilled
              220
              30
              –
              190Total
      kWh sales
              9,908
              126
              1.3
              9,782
 
 PEF’s
revenues, excluding fuel and other pass-through revenues of $608 million and
$645 million for the three months ended March 31, 2008 and 2007, respectively,
increased $22 million. The increase in revenues was primarily due to base rate
increases and increased wholesale revenues, partially offset by unfavorable
retail customer growth and usage. The increase in base rates was $19 million;
Hines 4 being placed in service contributed $10 million in additional revenues
and the transfer of Hines 2 cost recovery from the fuel clause to base rates
contributed $9 million. These base rate changes occurred in accordance with
PEF’s most recent base rate agreement. Wholesale revenues, excluding fuel and
other pass-through revenues increased $8 million primarily due to two new
contracts with one major customer and a contract amendment with another major
customer. In accordance with the contracts’ terms, the full financial impact of
the new and amended contract changes will not be realized until later in 2008.
PEF’s base rate and wholesale revenue favorability was partially offset by the
unfavorable retail customer growth and usage impact of $7 million.
  PEF
believes that the decline in general economic conditions, including weakness in
the housing markets in bothFloridaand
theUnited
States, has
contributed to a slowdown in customer growth and usage in its service territory.
In addition to lower average usage per customer, PEF
experienced significantly lower customer growth in the first quarter
of 2008 than had been experienced in recent periods. PEF’s average number
of net customers for the three months endedMarch 31,
2008,
compared to the same period in 2007 increased 7,000 customers. In comparison,
PEF's average number of net customers for the three months endedMarch 31,
2007,compared
to the same period in 2006, increased 31,000 customers.
  58
  PEF has secured and is pursuing additional wholesale
contracts that will mitigate, to a certain extent, the impact of lower retail
revenues. PEF cannot predict whether or to what extent the trends of declining
usage per customer and lower customer growth will continue to negatively impact
retail revenues or, if they do continue, the extent to which increased wholesale
revenues may offset such a negative impact.
  EXPENSES
  Fuel and Purchased
Power
  Fuel and
purchased power costs represent the costs of generation, which include fuel
purchases for generation, as well as energy purchased in the market to meet
customer load. Fuel and purchased power expenses are recovered primarily through
cost-recovery clauses and, as such, changes in these expenses do not have a
material impact on earnings. The difference between fuel and purchased power
costs incurred and associated fuel revenues that are subject to recovery is
deferred for future collection from or refund to customers.
  Fuel and
purchased power expenses were $524 million for the three months ended March 31,
2008, which represents a $24 million decrease compared to the same period in
2007. Fuel used in electric generation decreased $44 million to $341 million
compared to the same period in 2007. This decrease was due to lower deferred
fuel expense of $88 million, partially offset by increased current year fuel
costs of $44 million. The lower deferred fuel expense was primarily due to the
regulatory approval to lower the fuel factor for customers effective January
2008 as a result of over-recovery of fuel costs in the prior year. The increase
in current year fuel costs was primarily due to a change in generation mix as a
percentage of generation supplied by natural gas in response to plant outages
and higher system requirements. Purchased power costs were $20 million higher
for the three months ended March 31, 2008, due to increased current year
purchases of $19 million as a result of higher fuel costs.
  Operation and
Maintenance
  Operation
and maintenance expenses (O&M) were $203 million for the three months ended
March 31, 2008, which represents a $28 million increase when compared to the
same period in 2007. O&M expenses increased $26 million related to an
increase in storm damage reserves, which began in August 2007 and will continue
through August 2008, and $3 million related to higher outage restoration,
partially offset by a $5 million sales and use tax audit adjustment and $4
million lower environmental cost recovery (ECRC) costs due to deferral of
expenses. The storm damage reserve and ECRC expenses are recovered through
cost-recovery clauses and, therefore, have no material impact on
earnings.
  Depreciation and
Amortization
  Depreciation
and amortization expense was $76 million for the three months ended March 31,
2008, which represents a $21 million decrease compared to the same period in
2007. Depreciation and amortization expense decreased $26 million due to lower
amortization of unrecovered storm restoration costs, partially offset by the
impact of depreciable asset base increases. Storm restoration costs, which were
fully amortized in August 2007, were recovered through a cost-recovery clause
and, therefore, have no material impact on earnings.
  Total Other
Income
  Total
other income of $18 million increased $10 million for the three months ended
March 31, 2008, compared to the same period in 2007, primarily due to $11
million favorable AFUDC equity related to costs associated with large
construction projects. We expect AFUDC equity to continue to increase for the
remainder of 2008, primarily due to increased spending on environmental
initiatives and other large construction projects.
  Total Interest Charges,
net
  Total
interest charges, net were $44 million for the three months ended March 31,
2008, which represents a $7 million increase compared to the same period in
2007. The increase was primarily due to $9 million higher interest as a result
of higher average debt outstanding, partially offset by $3 million favorable
AFUDC debt related to costs associated with large construction
projects.
  59
  Income Tax
Expense
  Income
tax expense increased $2 million for the three months ended March 31, 2008,
compared to the same period in 2007, primarily due to the $3 million tax impact
of higher pre-tax income compared to the prior year, $1 million prior year
changes in tax estimates and the $1 million impact of tax levelization,
discussed below, partially offset by the $4 million impact of the increase in
AFUDC equity discussed above. AFUDC equity is excluded from the calculation of
income tax expense. GAAP requires companies to apply a levelized effective tax
rate to interim periods that is consistent with the estimated annual effective
tax rate. PEF’s income tax expense was increased by $1 million for the three
months ended March 31, 2008 compared to no impact for the three months ended
March 31, 2007, in order to maintain an effective tax rate consistent with the
estimated annual rate. Fluctuations in estimated annual earnings and the timing
of various permanent items of income or deduction can cause fluctuations in the
effective tax rate for interim periods. Therefore, this adjustment will vary
each quarter, but will have no effect on net income for the year.
  CORPORATE
AND OTHER
  The
Corporate and Other segment primarily includes the operations of the Parent,
PESC and other miscellaneous nonregulated businesses that do not separately meet
the quantitative disclosure requirements as a separate business segment.
Corporate and Other expense is summarized below:
  Three
      Months Ended March 31,(in
      millions)
              
              2008
              
              
              2007Other
      interest expense
              
              $
              (54
              )
              
              $
              (48
              )Contingent
      value obligations
              
              
              –
              
              
              
              1Tax
      levelization
              
              
              (1
              )
              
              
              (3
              )Other
      income tax benefit
              
              
              17
              
              
              
              22Other
              
              
              (1
              )
              
              
              (6
              )Corporate
      and Other after-tax expense
              
              $
              (39
              )
              
              $
              (34
              )
 
 Other
interest expense increased $6 million for the three months ended March 31, 2008,
compared to the same period in 2007. The increase for the three months ended
March 31, 2008, was primarily due to an $8 million decrease in the interest
allocated to discontinued operations. The decrease in interest expense allocated
to discontinued operations resulted from the allocations of interest expense in
early 2007 for operations that were sold later in 2007. Interest expense
allocated to discontinued operations was $1 million and $9 million for the three
months ended March 31, 2008 and 2007, respectively.
  Progress
Energy issued 98.6 million Contingent Value Obligations (CVOs) in connection
with the acquisition of Florida Progress Corporation (Florida Progress) in 2000.
Each CVO represents the right of the holder to receive contingent payments based
on the performance of four synthetic fuels facilities owned by Progress Energy.
The payments, if any, are based on the net after-tax cash flows the facilities
generate. At March 31, 2008 and 2007, the CVOs had fair values of approximately
$34 million and $31 million, respectively. We recorded an unrealized gain of $1
million for the three months ended March 31, 2007, 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 $0.35 and $0.31 at March 31, 2008 and
2007, respectively.
  GAAP
requires companies to apply a levelized effective tax rate to interim periods
that is consistent with the estimated annual effective tax rate. Income tax
expense was increased by $1 million for the three months ended March 31, 2008,
compared to an increase of $3 million for the three months ended March 31, 2007,
in order to maintain an effective rate consistent with the estimated annual
rate. Fluctuations in estimated annual earnings and the timing of various
permanent items of income or deduction can also cause fluctuations in the
effective tax rate for interim periods. Therefore, this adjustment will vary
each quarter, but will have no effect on net income for the year.
  Other
income tax benefit decreased $5 million for the three months ended March 31,
2008, compared to the same period in 2007, primarily due to the tax impact of
employee benefits.
  60
 Other
decreased $5 million for the three months ended March 31, 2008, compared to the
same period in 2007, primarily due to decreased legal expenses in
2008.
  DISCONTINUED
OPERATIONS
  We
divested multiple nonregulated businesses during 2008 and 2007 in accordance
with our business strategy to reduce our business risk and to focus on the core
operations of the Utilities.
  TERMINALS
OPERATIONS AND SYNTHETIC FUELS BUSINESSES
  On March
7, 2008, we sold coal terminals and docks in West Virginia and Kentucky
(Terminals) for $71 million in gross cash proceeds. The terminals have 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. As a result, 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 as defined under Section 29 (Section 29) of the Internal
Revenue Code (the Code). The production and sale of these products qualified for
federal income tax credits so long as certain requirements were satisfied.
Synthetic fuels were generally not economical to produce and sell absent the
credits. On September 14, 2007, we idled production of synthetic fuels at our
majority-owned synthetic fuels facilities due to the high level of oil prices.
On October 12, 2007, based upon the continued high level of oil prices,
unfavorable oil price projections through the end of 2007, and the expiration of
the synthetic fuels tax credit program at the end of 2007, we permanently ceased
production of synthetic fuels at our majority-owned facilities. 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. In accordance
with FASB Statement of Financial Accounting Standards (SFAS) No. 144,
“Accounting for the Impairment or Disposal of Long-Lived Assets”, operations
must be abandoned prior to reporting them as discontinued operations. All
periods have been restated to reflect the abandoned operations of our synthetic
fuels businesses as discontinued operations.
 
 Terminals
and the synthetic fuels businesses collectively generated net earnings from
discontinued operations of $12 million and $71 million for the three months
ended March 31, 2008 and 2007, respectively. The decrease in net earnings from
discontinued operations is primarily due to the 2007 expiration of the tax
credit program.
  CCO
– GEORGIA OPERATIONS
  On March
9, 2007, our subsidiary, Progress Ventures, Inc. (PVI), entered into a series of
transactions to sell or assign substantially all of its Competitive Commercial
Operations (CCO) physical and commercial assets and liabilities. Assets divested
include approximately 1,900 megawatts (MW) of gas-fired generation assets in
Georgia. The sale of the generation assets closed on June 11, 2007, for a net
sales price of $615 million. We recorded an estimated loss of $226 million in
December 2006. Based on the terms of the final agreement, during the quarter
ended March 31, 2007, we reversed $16 million after-tax of the impairment
recorded in 2006.
  Additionally,
on June 1, 2007, PVI closed the transaction involving the assignment of a
contract portfolio consisting of full-requirements contracts with 16 Georgia
electric membership cooperatives (the Georgia Contracts), forward gas and power
contracts, gas transportation, structured power and other contracts to a third
party. This represents substantially all of our nonregulated energy marketing
and trading operations. As a result of the assignments, PVI made a net cash
payment of $347 million, which represents the net cost to assign the Georgia
Contracts and other related contracts. In the quarter ended June 30, 2007, we
recorded a charge associated with the costs to exit the Georgia Contracts, and
other related contracts, of $349 million after-tax. We used the net proceeds
from these transactions for general corporate purposes.
  CCO’s
operations generated net earnings from discontinued operations of $43 million
for the three months ended March 31, 2007.
  61
 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. These assets include Powell Mountain Coal Co. and Dulcimer Land Co.,
which consist of approximately 30,000 acres in Lee County, Va. and Harlan
County, Ky. The property contains an estimated 40 million tons of high quality
coal reserves. 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 and $4 million for the three months ended March 31, 2008 and
2007, respectively.
 
 OTHER
DIVERSIFIED BUSINESSES
 
 On
October 2, 2006, we sold our natural gas drilling and production business (Gas)
to EXCO Resources, Inc. for approximately $1.1 billion in net proceeds. Based on
the net proceeds associated with the sale, we recorded an after-tax net gain on
disposal of $300 million during the year ended December 31, 2006. We recorded an
after-tax loss of $1 million during the three months ended March 31, 2007,
primarily related to working capital adjustments.
  On March
24, 2005, we completed the sale of Progress Rail Services Corporation (Progress
Rail) to One Equity Partners LLC, a private equity firm unit of J.P. Morgan
Chase & Co. During the three months ended March 31, 2008, we recorded an
after-tax gain on disposal of $1 million in connection with reduction of
guarantees and indemnifications provided by Progress Fuels and Progress Energy
for certain legal, tax and environmental matters to One Equity Partners, LLC
(SeeNote 13B). The ultimate resolution of these matters could result in
adjustments to the loss on disposal in future periods.
  Also
included in discontinued operations are earnings from other fuels businesses of
$1 million, net of tax, for the three months ended March 31, 2007.
  LIQUIDITY AND CAPITAL
RESOURCES
  OVERVIEW
  Progress
Energy, Inc. is a holding company and, as such, has no revenue-generating
operations of its own. Our primary cash needs at the Parent level are our common
stock dividend and interest and principal payments on our $2.6 billion of senior
unsecured debt. Our ability to meet these needs is dependent on the earnings and
cash flows of the Utilities, and the ability of the Utilities to pay dividends
or repay funds to us. As discussed under “Future Liquidity and Capital
Resources” below, synthetic fuels tax credits provide an additional source of
liquidity as those credits are realized. Our other significant cash requirements
arise primarily from the capital-intensive nature of the Utilities’ operations,
including expenditures for environmental compliance. We rely upon our operating
cash flow, substantially all of which is generated by the Utilities, commercial
paper and bank facilities, and our ability to access the long-term debt and
equity capital markets for sources of liquidity.
  The
majority of our operating costs are related to the Utilities. Most of these
costs are recovered from ratepayers in accordance with various rate plans. We
are allowed to recover certain fuel, purchased power and other costs incurred by
PEC and PEF through their respective recovery clauses. The types of costs
recovered through clauses vary by jurisdiction. Fuel price volatility can lead
to over- or under-recovery of fuel costs, as changes in fuel prices are not
immediately reflected in fuel surcharges due to regulatory lag in setting the
surcharges. As a result, fuel price volatility can be both a source of and a use
of liquidity resources, depending on what phase of the cycle of price volatility
we are experiencing. Changes in the Utilities’ fuel and purchased power costs
may affect the timing of cash flows, but are not expected to materially affect
net income.
  62
 As a
registered holding company, we are subject to regulation by the Federal Energy
Regulatory Commission (FERC), including for the issuance and sale of securities
as well as the establishment of intercompany extensions of credit (utility and
non-utility money pools). PEC and PEF participate in the utility money pool,
which allows the two utilities to lend to and borrow from each other. A
non-utility money pool allows our nonregulated operations to lend to and borrow
from each other. The Parent can lend money to the utility and non-utility money
pools but cannot borrow funds.
  63
  Cash from
operations, short-term and long-term debt, limited ongoing equity sales from our
Investor Plus Stock Purchase Plan and employee benefit and stock option plans,
and proceeds from the sale of the remainder of our nonregulated businesses
completed in the first quarter, are expected to fund capital expenditures and
common stock dividends for 2008. For the fiscal year 2008, we anticipate
realizing an aggregate amount of approximately $100 million from the sale of
stock through these plans.
  We
believe our internal and external liquidity resources will be sufficient to fund
our current business plans. Risk factors associated with credit facilities and
credit ratings are discussed in Item 1A, “Risk Factors” in the 2007 Form
10-K.
  The
following discussion of our liquidity and capital resources is on a consolidated
basis.
  HISTORICAL
FOR 2008 AS COMPARED TO 2007
  CASH
FLOWS FROM OPERATIONS
  Cash from
operations is the primary source used to meet operating requirements and capital
expenditures. Net cash provided by operating activities increased by $461
million for the three months ended March 31, 2008, when compared to the
corresponding period in the prior year. The increase in operating cash flow was
primarily due to a $252 million tax payment made in 2007 related to the sale of
Gas; the settlement of $247 million of derivative receivables primarily related
to derivative contracts for our former synthetic fuels businesses (see Note 9);
and a $131 million impact from accounts payable, driven by the timing of
purchases and payments to vendors at the Utilities. These impacts were partially
offset by a $108 million decrease in collateral held associated with the
synthetic fuels derivative contracts discussed above and an $82 million decrease
in the recovery of fuel costs at PEF.
  INVESTING
ACTIVITIES
  Net cash
used by investing activities increased by $143 million for the three months
ended March 31, 2008, when compared to the corresponding period in the prior
year. This is due primarily to a $147 million increase in capital expenditures
for utility property, primarily due to a $137 million increase in environmental
compliance spending at PEF and a $75 million increase in net purchases of
short-term investments included in available-for-sale securities and other
investments. These impacts were partially offset by a $65 million increase in
proceeds from sales of discontinued operations and other assets, net of cash
divested. Available-for-sale securities and other investments include marketable
debt and equity securities and investments held in nuclear decommissioning and
benefit investment trusts.
  During
the three months ended March 31, 2008, proceeds from sales of discontinued
operations and other assets primarily included proceeds from the sale of
Terminals and Coal Mining (see Notes 3A and 3C). During the three months ended
March 31, 2007, proceeds from sales of discontinued operations and other assets
primarily included working capital adjustments for Gas and the sale of poles at
Progress Telecommunications Corporation.
  FINANCING
ACTIVITIES
  Net cash
used by financing activities increased by $41 million for the three months ended
March 31, 2008, when compared to the corresponding period in the prior year. The
change in cash used by financing activities was primarily due to the financing
activities discussed below, $117 million in net short-term borrowings in 2007,
and $85 million in cash distributions to minority interests of consolidated
subsidiaries related settlement of Ceredo Synfuel LLC’s (Ceredo) synthetic fuels
derivatives contracts (See Note 9).
  On
February 1, 2008, PEF paid at maturity $80 million of its 6.875% First Mortgage
Bonds with available cash on hand and commercial paper borrowings.
  On March
12, 2008, PEC and PEF amended their revolving credit agreements (RCA) with a
syndication of financial institutions to extend the termination date by one
year. The extensions were effective for both utilities on March 28, 2008. PEC’s
RCA is now scheduled to expire on June 28, 2011, and PEF’s RCA is now scheduled
to expire on March 28, 2011.
  64
  On March
13, 2008, PEC issued $325 million of First Mortgage Bonds, 6.30% Series due
2038. The proceeds were used to repay the maturity of PEC’s $300 million 6.650%
Medium-Term Notes, Series D, due April 1, 2008 and the remainder was placed in
temporary investments for general corporate use as needed.
  On April
14, 2008, we amended our RCA with a syndication of financial institutions to
extend the termination date by one year.The
extension was effective onMay 3,
2008.Our RCA is now scheduled to expire on May 3,
2012.
  At
December 31, 2007, we had 500 million shares of common stock authorized under
our charter, of which 260 million shares were outstanding. For the three months
ended March 31, 2008 and 2007, respectively, we issued approximately 0.5 million
shares and 1.5 million shares of common stock resulting in approximately $20
million and $65 million in proceeds. Included in these amounts were
approximately 0.4 million shares and 0.2 million shares for proceeds of
approximately $19 million and $11 million, respectively, to meet the
requirements of the Progress Energy 401(k) Savings and Stock Ownership Plan
(401(k)) and the Investor Plus Stock Purchase Plan.
  FUTURE
LIQUIDITY AND CAPITAL RESOURCES
  At March
31, 2008, there were no material changes in our “Capital Expenditures,” “Other
Cash Needs,” “Credit Facilities,” or “Credit Rating Matters” as compared to
those discussed under LIQUIDITY AND CAPITAL RESOURCES in Item 7 to the 2007 Form
10-K, other than as described below and under “Credit Rating Matters”,
“Regulatory Matters and Recovery of Costs” and “Financing
Activities.”
 
 The
Utilities produce substantially all of our consolidated cash from operations. We
expect that the Utilities will continue to produce substantially all of the
consolidated cash flows from operations over the next several years. Our
synthetic fuels businesses, whose operations have been abandoned and
reclassified to discontinued operations, have historically produced significant
earnings from the generation of tax credits (See “Other Matters – Synthetic
Fuels Tax Credits”). These tax credits have yet to be realized in cash due to
the difference in timing of when tax credits are recognized for financial
reporting purposes and realized for tax purposes. At March 31, 2008, we have
carried forward $837 million of deferred tax credits. Realization of these tax
credits is dependent upon our future taxable income, which is expected to be
generated primarily by the Utilities.
 
 With the
exception of the proceeds in the first quarter of 2008 from the sale of
Terminals and Coal Mining (See Notes 3A and 3C), the absence of cash flow
resulting from divested businesses is not expected to impact our future
liquidity or capital resources as these businesses in the aggregate have been
largely cash flow neutral over the last several years.
 
 Cash from
operations plus availability under our credit facilities and shelf registration
statements is expected to be sufficient to meet our requirements in the near
term. To the extent necessary, we may also use limited ongoing equity sales from
our Investor Plus Stock Purchase Plan and employee benefit and stock option
plans to meet our liquidity requirements.
 
 We issue
commercial paper to meet short-term liquidity needs. In the latter half of 2007,
the short-term credit markets tightened, resulting in higher interest rate
spreads and shorter durations. In the latter half of the first quarter of 2008,
the market has improved; however, there has been volatility on commercial paper
spreads. If liquidity conditions deteriorate and negatively impact the
commercial paper market, we will need to evaluate other, potentially more
expensive, options for meeting our short-term liquidity needs, which may include
borrowing from our RCAs, issuing short-term floating rate notes, and/or issuing
long-term debt.
  Progress
Energy has approximately $9.9 billion in outstanding debt. Only $860 million of
our debt is insured. These bonds are obligations of the Utilities and are traded
in the tax-exempt auction rate securities market. Ambac Assurance Corporation
insures approximately $620 million of the bonds and XL Capital Assurance, Inc.
insures the remaining $240 million. To date, auctions for the Utilities’ bonds
have seen an increase in the interest rates that are periodically reset at each
auction. Since the downgrade of XL Capital Assurance, Inc. on February 7, 2008,
by Moody’s Investors Service, Inc. (Moody’s) and on February 25, 2008, by
Standard & Poor’s Rating Services (S&P), we have seen additional market
volatility and an increase in the reset interest rates for a portion of our
tax-exempt bonds. If additional downgrades by Moody’s or S&P occur, we could
experience additional volatility in this
  65
 market
and the potential for higher rate resets. We will continue to monitor this
market and evaluate options to mitigate our exposure to future
volatility.
 
 As
discussed in “Capital Expenditures,” under LIQUIDITY AND CAPITAL RESOURCES and
“Strategy” under INTRODUCTION in Item 7 to the 2007 Form 10-K and in “Other
Matters – Environmental Matters” of this Form 10-Q, over the long term,
compliance with environmental regulations and meeting the anticipated load
growth at the Utilities as described under “Other Matters – Increasing Energy
Demand” will require the Utilities to make significant capital investments.
These anticipated capital investments are expected to be funded through a
combination of cash from operations and issuance of long-term debt, preferred
stock and common equity, which are dependent on our ability to successfully
access capital markets. We may pursue joint ventures or similar arrangements
with third parties in order to share some of the financing and operational risks
associated with new baseload generation.
 
 The
amount and timing of future sales of securities will depend on market
conditions, operating cash flow, asset sales and our specific needs. We may from
time to time sell securities beyond the amount immediately needed to meet
capital requirements in order to allow for the early redemption of long-term
debt, the redemption of preferred stock, the reduction of short-term debt or for
other corporate purposes.
 
 At March
31, 2008, the current portion of our long-term debt was $1.197 billion, which we
expect to fund with a combination of cash from operations, commercial paper
borrowings and long-term debt.
 
 REGULATORY
MATTERS AND RECOVERY OF COSTS
  Regulatory
matters, as further discussed in Note 4 and “Other Matters – Regulatory
Environment”, and filings for recovery of environmental costs, as discussed in
Note 12 and in “Other Matters – Environmental Matters” of this filing and in
Note 21 and in “Other Matters – Regulatory Environment” and “Other Matters –
Environmental Matters” of the 2007 Form 10-K may impact our future liquidity and
financing activities. The impacts of these matters, including the timing of
recoveries from ratepayers, can be both a source of and a use of future
liquidity resources. Developments since our 2007 Form 10-K are discussed
below.
  PEC Pass-through Clause Cost
Recovery
  On April
30, 2008, PEC filed with the South Carolina Public Service Commission (SCPSC)
for an increase in the fuel rate charged to its South Carolina ratepayers. PEC
is asking the SCPSC to approve a $39 million increase in fuel rates for
under-recovered fuel costs associated with prior year settlements and to meet
future expected fuel costs. If approved, the increase would take effect July 1,
2008 and would increase residential electric bills by $5.86 per 1,000 kWh, or
6.1 percent, for fuel cost recovery. A hearing on the matter has been scheduled
by the SCPSC for June 12, 2008. We cannot predict the outcome of this
matter.
  As
discussed further in Note 4 and in “Other Matters – Regulatory Environment,”
South Carolina and North Carolina state energy legislation that became law in
2007 may impact our liquidity over the long term. Among other provisions, these
state energy laws provide mechanisms for recovery of certain baseload generation
construction costs and expand annual fuel clause mechanisms so that additional
costs may be recovered annually. PEC has begun implementing a series of
demand-side management (DSM) and energy-efficiency programs and deferred an
immaterial amount of implementation and program costs for future recovery. On
April 29 and May 1, 2008, PEC filed for NCUC approval of a total of five DSM and
energy-efficiency programs. We cannot predict the outcome of these filings or
whether the proposed programs will produce the expected operational and economic
results.
  On
December 21, 2007, the SCPSC issued an order granting PEC’s petition seeking
authorization to create a deferred account for DSM and energy-efficiency
expenses. As a result, PEC has deferred an immaterial amount of implementation
and program costs through March 31, 2008, for future recovery in the South
Carolina jurisdiction. PEC anticipates applying for a DSM and energy-efficiency
clause to recover the costs of these programs in 2008. We cannot predict the
outcome of this matter.
  On
February 29, 2008, the North Carolina Utilities Commission (NCUC) issued an
order adopting final rules for implementing North Carolina’s comprehensive
energy legislation. Among other things, the order establishes a schedule and
filing requirements for DSM and energy-efficiency cost recovery and financial
incentives. Rates for
  66
 the DSM
and energy-efficiency clause and the North Carolina Renewable Energy and Energy
Efficiency Portfolio Standard (REPS) clause will be set based on projected costs
with true-up provisions.
  On April
30, 2008, PEC submitted a revised Open Access Transmission Tariff (OATT)
filing, including a settlement agreement, with the FERC requesting an increase
in transmission rates. The settlement proposed a formula rate with a rate of
return on equity of 10.8 percent as well as recovery of the wholesale portion of
the terminated GridSouth project startup costs over five years. If approved by
FERC, the new rates would be effective July 1, 2008, and PEC estimates the
impact of the new rates will increase 2008 revenues by $6 million to $8 million.
We cannot predict the outcome of this matter.
  PEF Pass-through Clause Cost
Recovery
 
 On
October 10, 2007, the Florida Public Service Commission (FPSC) issued an order
requiring PEF to refund its ratepayers approximately $14 million, inclusive of
interest, over a 12-month period beginning January 1, 2008. Neither PEF nor
Florida’s Office of the Public Counsel (OPC) filed an appeal to the Florida
Supreme Court of the FPSC’s October 10, 2007 order. The FPSC also ordered PEF to
address whether it was prudent in its 2006 and 2007 coal purchases for Crystal
River Units No. 4 and 5 coal-fired steam turbines (CR4 and CR5). PEF believes
its coal procurement practices have been prudent. We anticipate that a hearing
will be held on the 2006 and 2007 coal purchases in January 2009. We cannot
predict the outcome of this matter.
  On
February 29, 2008, PEF filed a petition for recovery of costs incurred to uprate
Crystal River Unit No. 3 Nuclear Plant (CR3) in 2007 and 2006 under Florida’s
comprehensive energy legislation and the FPSC’s nuclear cost-recovery rule based
on the regulatory precedence established by a FPSC order to an unaffiliated
Florida utility for a nuclear uprate project. The FPSC is scheduled to vote on
this matter by October 2008. We cannot predict the outcome of this
matter.
  On May 1,
2008, PEF filed with the FPSC for an increase in the capacity cost-recovery
charge under the FPSC nuclear cost-recovery rule. PEF is asking the FPSC to
approve a $25 million increase in the capacity cost recovery rate for costs
associated with the CR3 uprate. If approved, the increase would take effect with
the first billing cycle for 2009 and would increase residential electric bills
by $0.70 per 1,000 kWh. Also included in this filing was a revision to the
estimate provided in the need determination proceeding to include indirect
costs, for a total original estimate of $439 million. After PEF's completion of
a transmission study and additional engineering studies, the current project
estimate is $364 million. A hearing on the matter has been scheduled by the FPSC
for September 2008, and the FPSC is scheduled to vote on this matter by October
2008. We cannot predict the outcome of this matter.
  PEF has
received approval from the FPSC for recovery through the ECRC of the majority of
costs associated with the remediation of distribution and substation
transformers which were estimated to be $27 million at March 31, 2008.
Additionally, on November 6, 2006, the FPSC approved PEF’s petition for 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 CAMR). The FPSC also approved cost recovery of prudently
incurred costs necessary to achieve this strategy, which are currently estimated
to be $1.2 billion to $2.2 billion.
  Nuclear Cost
Recovery
 
 The FPSC
approved new rules on February 13, 2007, that allow PEF to recover prudently
incurred siting, preconstruction costs and AFUDC on an annual basis through the
capacity cost-recovery clause. The nuclear cost-recovery rule also has a
provision to recover costs should the project be abandoned once 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. Such amounts will not be included in
PEF’s rate base when the plant is placed in commercial operation. 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.
 
 67
 As
discussed further in Note 4 and “Other Matters – Nuclear”, on March 11, 2008,
PEF filed a petition for an affirmative Determination of Need for its proposed
Levy Units 1 and 2 nuclear power plants, together with the associated
facilities, including transmission lines and substation facilities. The filed,
non-binding project cost estimate for Levy Units 1 and 2 is approximately $14
billion for generating facilities and approximately $3 billion for associated
transmission facilities. A public hearing is scheduled for May 21-23, 2008, and
a vote by the FPSC is scheduled for July 15, 2008. On March 11, 2008, PEF also
filed a petition with the FPSC to open a discovery docket regarding the actual
and projected costs of the proposed Levy nuclear project. PEF filed the petition
to assist the FPSC in the timely and adequate review of the projects costs
recoverable under the FPSC nuclear cost-recovery rule. On May 1, 2008, PEF filed
a petition for recovery of both preconstruction and carrying charges on
construction costs incurred or anticipated to be incurred during 2008 and 2009.
Additionally, the filing included site selection costs of $38 million.
Subsequent to an affirmative determination of need from the FPSC on the Levy
nuclear project, PEF intends to file a formal petition to recover all prudently
incurred costs under the FPSC nuclear cost-recovery rule. A
decision by the FPSC on PEF’s 2008 cost-recovery filing is expected on or before
October 1, 2008. We cannot predict the outcome of these matters.
  OFF-BALANCE SHEET
ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS
  Our
off-balance sheet arrangements and contractual obligations are described
below.
  GUARANTEES
  As a part
of normal business, we enter into various agreements providing future financial
or performance assurances to third parties that are outside the scope of FASB
Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for
Guarantees, Including Indirect Guarantees of Indebtedness of Others.” These
agreements are entered into primarily to support or enhance the creditworthiness
otherwise attributed to Progress Energy or our subsidiaries on a stand-alone
basis, thereby facilitating the extension of sufficient credit to accomplish the
subsidiaries’ intended commercial purposes. Our guarantees include standby
letters of credit, surety bonds, performance obligations for trading operations
and guarantees of certain subsidiary credit obligations. At March 31, 2008, we
have issued $416 million of guarantees for future financial or performance
assurance, including $11 million at PEC and $2 million at PEF. Included in this
amount is $300 million of guarantees of certain payments of two wholly owned
indirect subsidiaries issued by the Parent (See Note 14). We do not believe
conditions are likely for significant performance under the guarantees of
performance issued by or on behalf of affiliates.
  At March
31, 2008, we have issued guarantees and indemnifications of certain asset
performance, legal, tax and environmental matters to third parties, including
indemnifications made in connection with sales of businesses, and for timely
payment of obligations in support of our nonwholly owned synthetic fuels
operations (See Note 13B).
  MARKET
RISK AND DERIVATIVES
  Under our
risk management policy, we may use a variety of instruments, including swaps,
options and forward contracts, to manage exposure to fluctuations in commodity
prices and interest rates. See Note 9 and Item 3, “Quantitative and Qualitative
Disclosures about Market Risk” of this Form 10-Q, for a discussion of market
risk and derivatives.
  CONTRACTUAL
OBLIGATIONS
  As part
of our ordinary course of business, we enter into various long- and short-term
contracts for fuel requirements at our generating plants. Through March 31,
2008, contracts procured though our subsidiaries have increased our aggregate
purchase obligations for fuel and purchased power by $4.287 billion from $17.644
billion, as stated in Note 22A in the 2007 Form 10-K. In March 2008, PEC issued
long-term debt totaling $325 million. These increases are discussed under “PEC”
and “PEF” below.
  68
 PEC
  Through
March 31, 2008, PEC’s fuel and purchase power commitments increased by $3.248
billion from $5.078 billion, as stated in Note 22A in the 2007 Form 10-K. This
increase is primarily related to coal purchase commitments, of which
approximately $2 billion will be incurred through 2012, with the remainder
incurred through 2018.
  On March
13, 2008, PEC issued $325 million of First Mortgage Bonds, 6.30% Series due 2038
(See Note 6).
  PEF
  Through
March 31, 2008, PEF’s fuel and purchase power commitments increased by $1.039
billion from $12.566 billion, as stated in Note 22A in the 2007 Form 10-K.
Approximately $640 million of this increase is due to coal purchase commitments,
of which approximately $191 million will be incurred through 2012, with the
remainder incurred through 2018. Additionally, approximately $470 million of the
increase will be incurred in the period 2014 through 2027 and is due to the
impact of rising natural gas prices under a long-term gas supply agreement that
was entered into in December 2004. Payments under this agreement are based on a
published market
price index. Contractual obligations under this contract are based on estimated
future market prices.
  OTHER
MATTERS
  SYNTHETIC
FUELS TAX CREDITS
  Prior to
2008, we have had substantial operations associated with the production of
coal-based solid synthetic fuels as defined under Section 29 of the Code
(Section 29). The production and sale of these products qualified for federal
income tax credits so long as certain requirements were satisfied, including a
requirement that the synthetic fuels differ significantly in chemical
composition from the coal used to produce such synthetic fuels and that the fuel
was produced from a facility that was placed in service before July 1, 1998.
Qualifying synthetic fuels facilities entitled their owners to federal income
tax credits based on the barrel of oil equivalent of the synthetic fuels
produced and sold by these plants. The tax credits associated with synthetic
fuels in a particular year were phased out when annual average market prices for
crude oil exceeded certain prices. Synthetic fuels were generally not economical
to produce and sell absent the credits. The synthetic fuels tax credit program
expired at the end of 2007.
  TAX
CREDITS
  Legislation
enacted in 2005 redesignated the Section 29 tax credit as a general business
credit under Section 45K of the Code (Section 45K) effective January 1, 2006.
The previous amount of Section 29 tax credits that we were allowed to claim in
any calendar year through December 31, 2005, was limited by the amount of our
regular federal income tax liability. Section 29 tax credit amounts allowed but
not utilized are carried forward indefinitely as deferred alternative minimum
tax credits. The redesignation of Section 29 tax credits as a Section 45K
general business credit removed the regular federal income tax liability limit
on synthetic fuels production and subjects the credits to a 20-year carry
forward period.
  Total
Section 29/45K credits generated through December 31, 2007 (including those
generated by Florida Progress prior to our acquisition), were $1.891 billion. As
of March 31, 2008, $1.054 billion had been used to offset regular federal income
tax liability and $837 million is being carried forward as deferred tax
credits.
  IMPACT
OF CRUDE OIL PRICES
  Section
29 provided that if the average wellhead price per barrel for unregulated
domestic crude oil for the year (Annual Average Price) exceeded the Threshold
Price, the amount of Section 29/45K tax credits were reduced for that year.
Also, if the Annual Average Price exceeded the price per barrel of unregulated
domestic crude oil at which the value of Section 29/45K tax credits are fully
eliminated (Phase-out Price), the Section 29/45K tax credits were eliminated for
that year. The Threshold Price and the Phase-out Price are adjusted annually for
inflation.
  When the
Annual Average Price fell between the Threshold Price and the Phase-out Price
for a year, the amount by which Section 29/45K tax credits were reduced depended
on where the Annual Average Price fell in that continuum. The Department of the
Treasury calculates the Annual Average Price based on the Domestic Crude Oil
  69
 First
Purchases Prices published by the Energy Information Agency (EIA). Because the
EIA publishes its information on a three-month lag, the secretary of the
Treasury finalizes the calculations three months after the year in question
ends. Thus, the Annual Average Price for calendar year 2007 was published on
April 1, 2008. Based on the Annual Average Price for calendar year 2007 of
$66.52, our $205 million of synthetic fuels tax credits generated during 2007
were reduced by 67 percent, or approximately $138 million.
  In
January 2007, we entered into derivative contracts to hedge economically a
portion of our 2007 synthetic fuels cash flow exposure to the risk of rising oil
prices over an average annual oil price range of $63 to $77 per barrel on a New
York Mercantile Exchange (NYMEX) basis. The notional quantity of these oil price
hedge instruments was 25 million barrels and provided protection for the
equivalent of approximately eight million tons of 2007 synthetic fuels
production and was marked-to-market with changes in fair value recorded through
earnings. Approximately 34 percent of the notional quantity of these contracts
was entered into by Ceredo. As discussed below in “Sales of Partnership
Interests” and in Notes 1C and 3F, we disposed of our 100 percent ownership
interest in Ceredo in March 2007. For the three months ended March 31, 2007, we
recorded net pre-tax gains of $45 million related to these contracts, including
$15 million attributable to Ceredo, of which less than $1 million was attributed
to minority interest for the portion of the gain subsequent to disposal. The
derivative contracts ended on December 31, 2007, and were settled for cash on
January 8, 2008, with no material impact on 2008 earnings.
  SALES
OF PARTNERSHIP INTERESTS
  In March
2007, we disposed of, through our subsidiary Progress Fuels, our 100 percent
ownership interest in Ceredo, a subsidiary that produced and sold qualifying
coal-based solid synthetic fuels, to a third-party buyer. In addition, we
entered into an agreement to operate the Ceredo facility on behalf of the buyer.
At closing, we received cash proceeds of $10 million and a non-recourse note
receivable of $54 million. Payments on the note were received as we produced and
sold qualifying coal-based solid synthetic fuels on behalf of the buyer. We
received final payment on the note related to 2007 production of $5 million
during the quarter ended March 31, 2008. The total amount of the proceeds was
subject to adjustment once the final value of the 2007 Section 29/45K credits
was known. This adjustment resulted in a $7 million reduction of the purchase
price during the three months ended March 31, 2008. For the quarter ended March
31, 2008, we recorded gains on disposal of $5 million based on the value of the
2007 Section 29/45K tax credits. The operations of Ceredo were reclassified to
discontinued operations, net of tax on the Consolidated Statements of Income.
Subsequent to the disposal, we remained the primary beneficiary of Ceredo and
continued to consolidate Ceredo in accordance with FASB Interpretation No. 46R,
“Consolidation of Variable Interest Entities – an Interpretation of ARB No. 51”,
but we have recorded a 100 percent minority interest. Consequently, subsequent
to the disposal there is no net earnings impact from Ceredo’s operations, which
ceased as of December 31, 2007. In connection with the disposal, Progress Fuels
and Progress Energy provided guarantees and indemnifications for certain legal
and tax matters to the buyer, which reduces any gain. The ultimate resolution of
these matters could result in adjustments to the gain on disposal in future
periods. See Note 3F for additional discussion of this transaction and Note 13B
for a general discussion of guarantees.
  In June
2004, through our subsidiary Progress Fuels, we sold in two transactions a
combined 49.8 percent partnership interest in Colona Synfuel Limited
Partnership, LLLP (Colona), one of our coal-based solid synthetic fuels
facilities. Substantially all proceeds from the sales were received over time,
which is typical of such sales in the industry. Gains from the sales were
recognized on a cost-recovery basis. Gain recognition was dependent on the
synthetic fuels production qualifying for Section 29/45K tax credits and the
value of such tax credits as discussed above. Due to the impact on production
from the 2007 permanent cessation of the synthetic fuels facilities and pursuant
to the terms of the sales agreements, in January 2008, the purchasers abandoned
their interests in Colona. Through March 31, 2008, there has been no material
impact as a result of the abandonment.
  See Note
13C for additional discussion related to our synthetic fuels
operations.
  REGULATORY
ENVIRONMENT
  The
Utilities’ operations in North Carolina, South Carolina and Florida are
regulated by the NCUC, SCPSC and the FPSC, respectively. The Utilities are also
subject to regulation by the FERC, the Nuclear Regulatory Commission (NRC) and
other federal and state agencies common to the utility business. As a result of
regulation, many of the fundamental business decisions, as well as the rate of
return the Utilities are permitted to earn, are subject to the approval of one
or more of these governmental agencies.
  70
 To our
knowledge, there is currently no enacted or proposed legislation in North
Carolina, South Carolina or Florida that would give retail ratepayers the right
to choose their electricity provider or otherwise restructure or deregulate the
electric industry. We cannot anticipate when, or if, any of these states will
move to increase retail competition in the electric industry.
  The
retail rate matters affected by state regulatory authorities are discussed in
detail in Notes 4A and 4B. This discussion identifies specific retail rate
matters, the status of the issues and the associated effects on our consolidated
financial statements.
  During
the 2008 session, the Florida legislature passed comprehensive energy
legislation, which will become law upon signature by the governor, which we
expect will occur before the end of this summer. The legislation includes
provisions that would, among other things, (1) help enhance the ability to
cost-effectively site transmission lines; (2) require the FPSC to develop a
renewable portfolio standard that the FPSC would present to the legislature for
ratification in 2009; (3) direct the Florida Department of Environmental
Protection (FDEP) to develop rules establishing a cap and trade program to
regulate greenhouse gas emissions that the FDEP would present to the legislature
no earlier than January 2010 for
ratification by the legislature; 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.
  During
2007, the North Carolina legislature passed comprehensive energy legislation,
which became law on August 20, 2007. The law includes provisions for renewable
energy portfolio standards, expansion of the definition of the traditional fuel
clause and recovery of the costs of new DSM and energy-efficiency programs
through an annual DSM clause.
  On
February 29, 2008, the NCUC issued an order adopting final rules for
implementing North Carolina’s comprehensive energy legislation. These rules
provide filing requirements associated with the legislation. The order requires
PEC to submit its first annual REPS compliance plan by September 1, 2008, as
part of its integrated resource plan. Under the new rules, beginning in 2009,
PEC will also be required to file an annual REPS compliance report demonstrating
the actions it has taken to comply with the REPS requirement. The rules measure
compliance with the REPS requirement via renewable energy certificates (REC)
earned after January 1, 2008. The NCUC will pursue a third-party REC tracking
system, but will not develop or require participation in a REC trading platform
at this time. The order also establishes a schedule and filing requirements for
DSM and energy-efficiency cost recovery and financial incentives. Rates for the
DSM and energy-efficiency clause and the REPS clause will be set based on
projected costs with true-up provisions. On April 29 and May 1, 2008, PEC filed
for NCUC approval of a total of five DSM and energy-efficiency programs,
including the EnergyWiseTM and
distribution system demand response programs discussed below.
  On April
29, 2008, PEC filed for approval by the NCUC of its EnergyWiseTM program, which
is a residential program that offers customers an incentive to permit PEC to
remotely adjust central air conditioning and heat pumps in PEC’s eastern control
area and electric resistance heating and water heaters in PEC’s western control
area in order to duce peak demand. PEC’s goal for EnergyWiseTM is to have
the capability to reduce peak electricity demand by 200 MW by 2017.
 
 Also on
April 29, 2008, PEC filed for NCUC approval of its distribution system demand
response program, which will provide additional capability for reducing and
shifting peak electricity demand.  The program also will reduce the
level of natural electricity loss experienced over long distribution feeder
lines, thereby eliminating the need for additional power generation to
compensate for the line losses.  PEC anticipates that the program will
require an investment of approximately $260 million over five years and is
expected to reduce peak demand by 250 MW. This distribution system investment is
part of PEC’s broader “Smart Grid” strategy and is expected to provide a
foundation for additional initiatives, including enhanced system reliability
(through faster outage isolation and response) and new capabilities for
incorporating renewable energy resources and other distributed generation into
PEC’s energy mix. Such costs are expected to be recovered under the provisions
of the North Carolina comprehensive energy legislation.
  We cannot predict the
outcome of the April 29 and May 1, 2008 filings or whether the proposed programs
will produce the expected operational and economic results.
  71
 On July
13, 2007, the governor of Florida issued executive orders to address reduction
of greenhouse gas emissions. The executive orders call for the first
Southeastern state cap-and-trade program and include adoption of a maximum
allowable emissions level of greenhouse gases for Florida utilities. The
standard will require, at a minimum, the following three reduction milestones:
by 2017, emissions not greater than Year 2000 utility sector emissions; by 2025,
emissions not greater than Year 1990 utility sector emissions; and by 2050,
emissions not greater than 20 percent of Year 1990 utility sector
emissions.
  Among
other things, the executive orders also requested that the FPSC initiate a
rulemaking by September 1, 2007 that would (1) require Florida utilities to
produce at least 20 percent of their electricity from renewable sources; (2)
reduce the cost of connecting solar and other renewable energy technologies to
Florida’s power grid by adopting uniform statewide interconnection standards for
all utilities; and (3) authorize a uniform, statewide method to enable
residential and commercial customers, who generate electricity from on-site
renewable technologies of up to 1 MW in capacity, to offset their consumption
over a billing period by allowing their electric meters to turn backwards when
they generate electricity (net metering). The FPSC has held meetings regarding
the renewable portfolio standard but no actions have been taken or rules issued.
The Energy and Climate Action Team appointed by the governor submitted its
initial recommendations for implementation of the governor’s executive orders on
November 1, 2007.
The recommendations encourage the development and implementation of energy
efficiency and conservation measures, implementation of a climate registry, and
consideration of a cap-and-trade approach to reducing the state’s greenhouse gas
emissions. Additional development and discussion of the recommendations will
occur through a stakeholder process in 2008.The FDEP held its first
workshop on the greenhouse gas emissions cap on August 22, 2007, but we
anticipate drafts of the rule to be issued later in 2008. We cannot currently
predict the costs of complying with the laws and regulations that may ultimately
result from these executive orders. Our balanced solution, as described in
“Increasing Energy Demand”, includes greater investment in energy efficiency,
renewable energy and state-of-the-art generation and demonstrates our commitment
to environmental responsibility.
  LEGAL
  We are
subject to federal, state and local legislation and court orders. The specific
issues, the status of the issues, accruals associated with issue resolutions and
our associated exposures are discussed in detail in Note 13C.
  INCREASING
ENERGY DEMAND
  Meeting
the anticipated growth within the Utilities’ service territories will require a
balanced approach. The three main elements of this balanced solution are: (1)
expanding our energy efficiency programs; (2) investing in the development of
alternative energy resources for the future; and (3) operating state-of-the-art
plants that produce energy cleanly and efficiently by modernizing existing
plants and pursuing options for building new plants and associated transmission
facilities.
  We are
actively pursuing expansion of our energy-efficiency and conservation programs
as energy efficiency is one of the most effective ways to reduce energy costs,
offset the need for new power plants and protect the environment. Our
energy-efficiency program provides simple, low-cost ways for residential
customers to reduce energy use, promotes home energy checks, provides tools and
programs for large and small businesses to minimize their energy use and
provides an interactive internet Web site with online calculators, programs and
efficiency tips.
  We are
actively engaged in a variety of alternative energy projects, including solar,
hydrogen, biomass and landfill-gas technologies. We are evaluating the
feasibility of producing electricity from hog waste and other plant or animal
sources.
  In the
coming years, we will continue to invest in existing plants and consider plans
for building new generating plants. Due to the anticipated long-term growth in
our service territories, we estimate that we will require new generation
facilities in both Florida and the Carolinas toward the end of the next decade,
and we are evaluating the best available options for this generation, including
advanced design nuclear and gas technologies. At this time, no definitive
decisions have been made to construct new nuclear plants. While we pursue
expansion of energy- efficiency and conservation programs, PEC has announced a
two-year moratorium on constructing new coal-fired plants and that if PEC goes
ahead with a new nuclear plant, the new plant would not be online until at least
2018 (see “Nuclear” below).
  72
 As
authorized under Energy Policy Act of 2005 (EPACT), on October 4, 2007, the
United States Department of Energy (DOE) published final regulations for the
disbursement of up to $13 billion in loan guarantees for clean-energy projects
using innovative technologies. The guarantees, which will cover up to 100
percent of the amount of any loan for no more than 80 percent of the project
cost, are expected to spur development of nuclear, clean-coal and ethanol
projects. In 2008, Congress authorized $38.5 billion in loan guarantee authority
for innovative energy projects. Of the total provided, $18.5 billion is set
aside for nuclear power facilities, $2 billion for advanced nuclear facilities
for the "Front-end" of the nuclear fuel cycle, $10 billion for renewable and/or
energy efficient systems and manufacturing and distributed energy
generation/transmission and distribution, $6 billion for coal-based power
generation and industrial gasification at retrofitted and new facilities that
incorporate carbon capture and sequestration or other beneficial uses of carbon
and $2 billion for advanced coal gasification. We cannot predict if we will
pursue these loan guarantees.
  NUCLEAR
 
 Nuclear
generating units are regulated by the NRC. In the event of noncompliance, the
NRC has the authority to impose fines, set license conditions, shut down a
nuclear unit or take some combination of these actions, depending upon its
assessment of the severity of the situation, until compliance is
achieved.
  On
November 14, 2006, PEC filed an application with the NRC for a 20-year extension
of the Shearon Harris Nuclear Plant (Harris) operating license. The license
renewal application for Harris is currently under review by the NRC with a
decision expected in 2008.
  Our
nuclear units are periodically removed from service to accommodate normal
refueling and maintenance outages, repairs and certain other
modifications.
  We
previously announced that we are pursuing development of combined license (COL)
applications to potentially construct new nuclear plants in North Carolina and
Florida. Filing of a COL is not a commitment to build a nuclear plant but is a
necessary step to keep open the option of building a plant or plants. The NRC
estimates that it will take approximately three to four years to review and
process the COL applications.
  On
January 23, 2006, we announced that PEC selected a site at Harris to evaluate
for possible future nuclear expansion. We selected the Westinghouse Electric
AP1000 reactor design as the technology upon which to base PEC’s application
submission. On February 19, 2008, PEC filed its COL application with the NRC for
two additional reactors at Harris. On April 18, 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. The NRC will publish in the
near future an opportunity to intervene in the adjudicatory hearing required for
this application. Petitions to intervene in a hearing may be filed within 60
days of the notice, by anyone whose interest may be affected by the proposed
license and who wishes to participate as a party in the proceeding. If we
receive approval from the NRC and applicable state agencies, and if the
decisions to build are made, the new plant would not be online until at least
2018 (See “Increasing Energy Demand” above).
  On
December 12, 2006, we announced that PEF selected a site in Levy County, Fla.,
to evaluate for possible future nuclear expansion. We selected the Westinghouse
Electric AP1000 reactor design as the technology upon which to base PEF’s
application submission. PEF expects to file the application for the COL in 2008.
If we receive approval from the NRC and applicable state agencies, and if the
decision to build is made, safety-related construction activities could begin as
early as 2012, and a new plant could be online in 2016 (See “Increasing Energy
Demand” above). In 2007, PEF completed the purchase of approximately 5,000 acres
for the Levy County site and associated transmission needs. PEF filed a
Determination of Need petition with the FPSC on March 11, 2008. The hearing is
scheduled for May 21-23, 2008, and a vote by the FPSC is scheduled for July 15,
2008. We cannot predict the outcome of this matter.
  In 2007,
both the Levy County Planning Commission and the Board of Commissioners voted
unanimously in favor of PEF’s requests to change the comprehensive land use
plan. The Florida Department of Community Affairs (FDCA) reviewed the proposed
changes to the comprehensive land use plan and in their report, the FDCA
expressed concerns related to the intensity of use and environmental suitability
for some of the proposed amendments impacting PEF’s proposed Levy County nuclear
site. We anticipate that the Levy County Planning
  73
 Commission
will resolve the FDCA’s concerns without impact to the potential project
schedule. We cannot predict the outcome of this matter.
  In
addition, PEF expects to file its application for Site Certification with the
FDEP in the second quarter of 2008. A decision on PEF’s FDEP Site Certification
Application is expected in 2009.
  On March
11, 2008, PEF also filed a petition with the FPSC to open a discovery docket
regarding the actual and projected costs of the proposed Levy nuclear project.
PEF filed the petition to assist the FPSC in the timely and adequate review of
the projects costs recoverable under the FPSC nuclear cost-recovery rule. On May
1, 2008, PEF filed a petition for recovery of both preconstruction and carrying
charges on construction costs incurred or anticipated to be incurred during 2008
and 2009. Additionally, the filing included site selection costs of $38 million.
Subsequent to an affirmative determination of need from the FPSC on the Levy
nuclear project, PEF intends to file a formal petition to recover all prudently
incurred costs under the FPSC nuclear cost-recovery rule. A decision by the FPSC
on PEF’s 2008 cost-recovery filing is expected on or before October 1, 2008. We
cannot predict the outcome of this matter.
  On April
7, 2008, PEF signed a letter of intent with the Shaw Group Inc. and Westinghouse
Electric Co. to complete negotiations toward an engineering, procurement and
construction (EPC) contract for up to two Westinghouse AP1000 nuclear reactors
planned for construction at the Levy County, Fla. site. The letter of intent
authorizes the purchase of long lead time materials for the reactors. At this
time, no definitive decisions have been made to construct new nuclear
plants.
  A new
nuclear plant may be eligible for the federal production tax credits and risk
insurance provided by EPACT. EPACT provides an annual tax credit of 1.8 cents
per kWh for nuclear facilities for the first eight years of operation. The
credit is limited to the first 6,000 MW of new nuclear generation in the United
States and has an annual cap of $125 million per 1,000 MW of national MW
capacity limitation allocated to the unit. In April 2006, the Internal Revenue
Service (IRS) provided interim guidance that the 6,000 MW of production tax
credits generally will be allocated to new nuclear facilities that file license
applications with the NRC by December 31, 2008, had poured safety-related
concrete prior to January 1, 2014, and were placed in service before January 1,
2021. There is no guarantee that the interim guidance will be incorporated into
the final regulations governing the allocation of production tax credits.
Multiple utilities have announced plans to pursue new nuclear plants. There is
no guarantee that any nuclear plant we construct would qualify for these or
other incentives. We cannot predict the outcome of this matter.
  In
accordance with provisions of Florida’s comprehensive energy legislation enacted
in 2006, the FPSC ordered new rules in December 2006 that would allow
investor-owned utilities such as PEF to request recovery of certain planning and
construction costs of a nuclear power plant prior to commercial operation. The
FPSC issued a final rule on February 13, 2007, under which utilities will be
allowed to recover prudently incurred siting, preconstruction costs and AFUDC on
an annual basis through the capacity cost-recovery clause. The nuclear
cost-recovery rule also has a provision to recover costs should the project be
abandoned once 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. Such
amounts will not be included in a utility’s rate base when the plant is placed
in commercial operation. In addition, the rule will require the FPSC to conduct
an annual prudence review of the reasonableness and prudence of all such costs,
including construction costs, and such determination shall not be subject to
later review except upon a finding of fraud, intentional misrepresentation or
the intentional withholding of key information by the utility. Also, on February
1, 2007, the FPSC amended its power plant bid rules to, among other things,
exempt nuclear power plants from existing bid requirements.
  In 2007,
the South Carolina legislature ratified new energy legislation, which includes
provisions for cost-recovery mechanisms associated with nuclear baseload
generation. In 2007, the North Carolina legislature also passed new energy
legislation, which authorizes the NCUC to allow annual prudence reviews of
baseload generating plant construction costs and removes the requirement that a
public utility prove financial distress before it may include construction work
in progress in rate base and adjust rates, accordingly, in a general rate case
while a baseload generating plant is under construction (See “Other Matters –
Regulatory Environment”).
  74
 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 be precisely estimated.
  HAZARDOUS
AND SOLID WASTE MANAGEMENT
  The
provisions of the Comprehensive Environmental Response, Compensation and
Liability Act of 1980, as amended (CERCLA), authorize the Environmental
Protection Agency (EPA) to require the cleanup of hazardous waste sites. This
statute imposes retroactive joint and several liabilities. Some states,
including North Carolina, South Carolina and Florida, have similar types of
statutes. We are periodically notified by regulators, including the EPA and
various state agencies, of our involvement or potential involvement in sites
that may require investigation and/or remediation.
There are presently several sites with respect to which we have been notified of
our potential liability by the EPA, the state of North Carolina, the state of
Florida or potentially responsible parties (PRP) groups. Various organic
materials associated with the production of manufactured gas, generally referred
to as coal tar, are regulated under federal and state laws. PEC and PEF are each
PRPs at several manufactured gas plant (MGP) sites. We are also currently in the
process of assessing potential costs and exposures at other sites. These costs
are eligible for regulatory recovery through either base rates or cost-recovery
clauses (See Notes 4 and 12). Both PEC and PEF evaluate potential claims against
other PRPs and insurance carriers and plan to submit claims for cost recovery
where appropriate. The outcome of these potential claims cannot be predicted. No
material claims are currently pending. Hazardous and solid waste management
matters are discussed in detail in Note 12A.
  We accrue
costs to the extent our liability is probable and the costs can be reasonably
estimated in accordance with GAAP. Because the extent of environmental impact,
allocation among PRPs for all sites, remediation alternatives (which could
involve either minimal or significant efforts), and concurrence of the
regulatory authorities have not yet reached the stage where a reasonable
estimate of the remediation costs can be made, we cannot determine the total
costs that may be incurred in connection with the remediation of all sites at
this time. It is probable that current estimates could change and additional
losses, which could be material, may be incurred in the future.
  AIR
QUALITY AND WATER QUALITY
  We are,
or may ultimately be, subject to various current and proposed federal, state and
local environmental compliance laws and regulations, which would likely result
in increased capital expenditures and O&M expenses. Additionally, Congress
is considering legislation that would require additional reductions in air
emissions of nitrogen oxides (NOx), sulfur dioxide (SO2), carbon
dioxide (CO2) and
mercury. Some of these proposals establish nationwide caps and emission rates
over an extended period of time. This national multipollutant approach to air
pollution control could involve significant capital costs that could be material
to our financial position or results of operations. Control equipment that will
be installed pursuant to the provisions of the Clean Smokestacks Act, CAIR, CAVR
and mercury regulation, which are discussed below, may address some of the
issues outlined above. CAVR requires the installation of best available retrofit
technology (BART) on certain units. However, the outcome of these matters cannot
be predicted.
  The
following tables contain information about our current estimates of capital
expenditures to comply with environmental laws and regulations described below.
These costs are eligible for regulatory recovery through either base rates or
cost-recovery clauses. The outcome of future petitions for recovery cannot be
predicted. PEC has completed installation of controls to meet the NOx SIP Call
Rule under Section 110 of the Clean Air Act (NOx SIP Call) requirements. The NOx
SIP Call is not applicable to Florida. Expenditures for the NOx SIP Call include
the cost to install NOx controls under North Carolina’s and South Carolina’s
programs to comply with the federal eight-hour ozone standard. The air quality
controls installed to comply with the NOx SIP Call and Clean Smokestacks Act
will result in a reduction of the costs to meet the CAIR requirements for our
North Carolina units at PEC. Our estimates of capital expenditures to comply
with environmental laws and regulations are subject to periodic review and
revision and may vary significantly. The timing and extent of the costs for
future projects will depend upon final compliance strategies.
  75
  Progress
      EnergyAir and Water Quality Estimated
      Required Environmental Expenditures
                (in
      millions)
              Estimated
                Timetable
              Total
      Estimated
                Expenditures
              Cumulative
      Spent through
                March
      31, 2008Clean
      Smokestacks Act
              2002–2013
              $1,500
      – 1,600
              $919CAIR/CAVR/mercury
      regulation
              2005–2016
              1,300
      – 2,400
              492Total
      air quality
              
              2,800
      – 4,000
              1,411Clean
      Water Act Section 316(b)(a)
              
              –
              –Total
      air and water quality
              
              $2,800
      – 4,000
              $1,411
 
 PECAir and Water Quality Estimated
      Required Environmental Expenditures
                (in
      millions)
              Estimated
                Timetable
              Total
      Estimated
                Expenditures
              Cumulative
      Spent through
                March
      31, 2008Clean
      Smokestacks Act
              2002–2013
              $1,500
      – 1,600
              $919CAIR/CAVR/mercury
      regulation
              2005–2016
              100
      – 200
              13Total
      air quality
              
              1,600
      – 1,800
              932Clean
      Water Act Section 316(b)(a)
              
              –
              –Total
      air and water quality
              
              $1,600
      – 1,800
              $932
  PEFAir and Water Quality Estimated
      Required Environmental Expenditures
                (in
      millions)
              Estimated
                Timetable
              Total
      Estimated
                Expenditures
              Cumulative
      Spent through
                March
      31, 2008CAIR/CAVR/mercury
      regulation
              2005–2016
              $1,200
      – 2,200
              $479Clean
      Water Act Section 316(b)(a)
              
              –
              –Total
      air and water quality
              
              $1,200
      – 2,200
              $479
 
 (a)
              Compliance
      plans to meet the requirements of a revised or new implementing rule under
      Section 316(b) of the Clean Water Act will be determined upon finalization
      of the rule. See discussion under “Water
  Quality.”
 
 To date,
under the first phase of Clean Smokestacks Act emission reductions, all
environmental compliance projects at PEC’s Asheville and Lee plants and several
projects at PEC’s Roxboro plant have been placed in service. The remaining
projects at PEC’s two largest plants, Roxboro and Mayo, are under construction
and are expected to be completed in 2008 and 2009, respectively. The remaining
projects to comply with the second phase of emission reductions, which are
smaller in scope, have not yet begun. These estimates are conceptual in nature
and subject to change. As discussed below, our Clean Smokestacks Act compliance
costs have increased from December 31, 2007.
  To date,
expenditures at PEF for CAIR/CAVR/mercury 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. See discussion
of projects for Crystal River Units No. 1 and No. 2 to meet CAVR beyond-BART
requirements below. As a result of changes in the scope of work related to CAIR
and the court decision that vacated the delisting determination and the Clean
Air Mercury Rule (CAMR) discussed below, our estimated costs have decreased from
December 31, 2007. Our current estimated costs reflect only the completion of
engineering and design work in progress at the time that the CAMR was vacated.
Compliance plans and estimated costs to meet the requirements of new mercury
regulations will be determined when those new regulations are
finalized.
  New Source
Review
  The EPA
is conducting an enforcement initiative related to a number of coal-fired
utility power plants in an effort to determine whether changes at those
facilities were subject to New Source Review (NSR) requirements or New Source
Performance Standards under the Clean Air Act. We were asked to provide
information to the EPA as part of this initiative and cooperated in supplying
the requested information. The EPA has undertaken civil enforcement actions
against unaffiliated utilities as part of this initiative. Some of these actions
resulted in settlement agreements requiring expenditures by these unaffiliated
utilities, several of which were in excess of $1.0 billion. These
  76
 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.
  Clean Smokestacks
Act
  In June
2002, the Clean Smokestacks Act was enacted in North Carolina requiring the
state's electric utilities to reduce the emissions of NOx and SO2 from their
North Carolina coal-fired power plants in phases by 2013. PEC currently has
approximately 5,000 MW of coal-fired generation capacity in North Carolina that
is affected by the Clean Smokestacks Act. In March 2008, PEC filed its annual
estimate with the NCUC of the total capital expenditures to meet emission
targets under the Clean Smokestacks Act by the end of 2013, which were
approximately $1.5 billion to $1.6 billion at the time of the filing. The
increase in estimated total capital expenditures from the original 2002 estimate
of $813 million is primarily due to the higher cost and revised quantities of
construction materials, such as concrete and steel, refinement of cost and scope
estimates for the current projects, increases in the estimated inflation factor
applied to future project costs, and the impact of additional planning for
Sutton Unit No. 3 and Cape Fear Units No. 5 and No. 6. We are continuing to
evaluate various design, technology and new generation options that could
further change expenditures required by the Clean Smokestacks Act. O&M
expenses will significantly increase due to the cost of reagents, additional
personnel and general maintenance associated with the equipment. Recent
legislation in North Carolina and South Carolina expanded the traditional
fuel clause to include the annual recovery of reagents and certain other costs;
all other O&M expenses are currently recoverable through base rates. On
March 23, 2007, PEC filed a petition with the NCUC regarding future recovery of
costs to comply with the Clean Smokestacks Act, and on October 22, 2007, PEC
filed with the NCUC a settlement agreement with the NCUC Public Staff, Carolina
Utility Customers Association (CUCA) and Carolina Industrial Group for Fair
Utility Rates II (CIGFUR) supporting PEC’s proposal. The NCUC held a hearing on
this matter on October 30, 2007. On December 20, 2007, the NCUC approved the
settlement agreement on a provisional basis. See further discussion about the
Clean Smokestacks Act in Note 4A. We cannot predict the outcome of this
matter.
  Two of
PEC’s largest coal-fired generating units (the Roxboro No. 4 and Mayo Units)
impacted by the Clean Smokestacks Act are jointly owned. In 2005, PEC entered
into an agreement with the joint owner to limit their aggregate costs associated
with capital expenditures to comply with the Clean Smokestacks Act and
recognized a liability related to this indemnification (See Note
12B).
  Pursuant
to the Clean Smokestacks Act, PEC entered into an agreement with the state of
North Carolina to transfer to the state certain NOx and SO2 emissions
allowances that result from compliance with the collective NOx and SO2 emissions
limitations set in the Clean Smokestacks Act. The Clean Smokestacks Act also
required the state to undertake a study of mercury and CO2 emissions
in North Carolina. The future regulatory interpretation, implementation or
impact of the Clean Smokestacks Act cannot be predicted.
  Clean Air Interstate Rule,
Clean Air Mercury Rule and Clean Air Visibility Rule
  On March
10, 2005, the EPA issued the final CAIR. The EPA’s rule requires the District of
Columbia and 28 states, including North Carolina, South Carolina and Florida, to
reduce NOx and SO2 emissions
in order to reduce levels of fine particulate matter and impacts to visibility.
The CAIR sets emission limits to be met in two phases beginning in 2009 and
2015, respectively, for NOx and beginning in 2010 and 2015, respectively, for
SO2.
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 has
joined a coalition of Florida utilities that has filed a challenge to the CAIR
as it applies to Florida. While we consider it unlikely that this challenge
would eliminate the compliance requirements of the CAIR, it could potentially
reduce or delay our costs to comply with the CAIR. On March 25, 2008 the D. C.
Court of Appeals heard oral arguments in the litigation on the CAIR. The outcome
of this matter cannot be predicted.
  On March
15, 2005, the EPA finalized two separate but related rules: the CAMR that set
mercury emissions limits to be met in two phases beginning in 2010 and 2018,
respectively, and encouraged a cap-and-trade approach to achieving those caps,
and a delisting rule that eliminated any requirement to pursue a maximum
achievable control technology approach for limiting mercury emissions from
coal-fired power plants. Sixteen states subsequently petitioned for a review of
the EPA’s determination confirming the delisting. On February 8, 2008, the U.S.
Court of
  77
 Appeals
for the District of Columbia (D.C. Court of Appeals) decided in favor of the
petitioners and vacated the delisting determination and the CAMR. On March 24,
2008, the EPA and the Utility Air Regulatory Group filed petitions for rehearing
by the full court of appeals. The three states in which the Utilities operate
adopted mercury regulations implementing CAMR and submitted their state
implementation rules to the EPA. It is uncertain how the decision that vacated
the federal CAMR and the petitions for rehearing will affect the state rules.
The outcome of this matter cannot be predicted.
  On June
15, 2005, the EPA issued the final CAVR. The EPA’s rule requires states to
identify facilities, including power plants, built between August 1962 and
August 1977 with the potential to produce emissions that affect visibility in
156 specially protected areas, including national parks and wilderness areas. To
help restore visibility in those areas, states must require the identified
facilities to install BART to control their emissions. The reductions associated
with BART begin in 2013. CAVR included the EPA’s determination that compliance
with the NOx and SO2
requirements of CAIR may be used by states as a BART substitute. Plans for
compliance with CAIR and mercury regulation may fulfill BART obligations, but
the states could require the installation of additional air quality controls if
they do not achieve reasonable progress in improving visibility. On December 4,
2007, the FDEP finalized a Regional Haze implementation rule that requires
sources significantly impacting visibility in Class I areas to install
additional controls by December 31, 2017. PEC’s BART-eligible units are
Asheville Units No. 1 and No. 2, Roxboro Units No. 1, No. 2 and No. 3, and
Sutton Unit No. 3. PEF’s BART-eligible units are Anclote Units No. 1 and No.
2, Bartow Unit No. 3 and Crystal River Units No. 1 and No. 2. The outcome of
this matter cannot be predicted.
  PEC and
PEF are each developing an integrated compliance strategy to meet all the
requirements of the CAIR, CAVR and mercury regulation. We are evaluating various
design, technology and new generation options that could change PEC’s and PEF’s
costs to meet these requirements.
  The
integrated compliance strategy PEF anticipates implementing should provide most,
but not all, of the NOx reductions required by CAIR. Therefore, PEF anticipates
utilizing the cap-and-trade feature of CAIR by purchasing annual and seasonal
NOx allowances. Because the emission controls cannot be installed in time to
meet CAIR’s NOx requirements in 2009, PEF anticipates purchasing a higher level
of annual and seasonal allowances in that year. The costs of these allowances
would depend on market prices at the time these allowances are purchased. PEF
expects to recover the costs of these allowances through its Environmental Cost
Recovery Clause (ECRC).
  On
October 14, 2005, the FPSC approved PEF’s petition for the recovery of costs
associated with the development and implementation of an integrated strategy to
comply with the CAIR, CAMR and CAVR through the ECRC (see discussion above
regarding CAMR). On March 31, 2006, PEF filed a series of compliance
alternatives with the FPSC to meet these federal environmental rules. At the
time, PEF’s recommended proposed compliance plan included approximately $740
million of estimated capital costs expected to be spent through 2016, to plan,
design, build and install pollution control equipment at our Anclote and Crystal
River plants. On November 6, 2006, the FPSC approved PEF’s petition for its
integrated strategy to address compliance with CAIR, CAMR and CAVR. They also
approved cost recovery of prudently incurred costs necessary to achieve this
strategy. On June 1, 2007, PEF filed a supplemental petition for approval of its
compliance plan and associated contracts and recovery of costs for air pollution
control projects, which included approximately $1.0 billion to $2.3 billion of
estimated capital costs for the range of alternative plans. The estimated
capital cost for the recommended plan, which was $1.26 billion in the June 1,
2007 filing, represents the low end of the range in the table of estimated
required environmental expenditures shown above. On April 2, 2008, PEF filed a
petition for approval true-up of final environmental costs for the period
January 2007 to December 2007 and a review of the integrated clean air
compliance plan, which reconfirmed the efficacy of the recommended plan. The
difference in costs between the recommended plan and the high end of the range
represents the additional costs that may be incurred if pollution controls are
required on Crystal River Units No. 1 and No. 2 in order to comply with the
requirements of CAVR beyond BART, should reasonable progress in improving
visibility not be achieved, as discussed above. The increase from the estimates
filed in March 2006 is primarily due to the higher cost of labor and
construction materials, such as concrete and steel, and refinement of cost and
scope estimates for the current projects. These costs will continue to change
depending upon the results of the engineering and strategy development work
and/or increases in the underlying material, labor and equipment costs.
Subsequent rule interpretations, equipment availability, or the unexpected
acceleration of the initial NOx or other compliance dates, among other things,
could require acceleration of some projects. The outcome of this matter cannot
be predicted.
  78
 North Carolina Attorney
General Petition under Section 126 of the Clean Air Act
  In March
2004, the North Carolina attorney general filed a petition with the EPA, under
Section 126 of the Clean Air Act, asking the federal government to force
coal-fired power plants in 13 other states, including South Carolina, to reduce
their NOx and SO2 emissions.
The state of North Carolina contends these out-of-state emissions interfere with
North Carolina’s ability to meet national air quality standards for ozone and
particulate matter. On March 16, 2006, the EPA issued a final response denying
the petition. The EPA's rationale for denial is that compliance with CAIR will
reduce the emissions from surrounding states sufficiently to address North
Carolina's concerns. On June 26, 2006, the North Carolina attorney general filed
a petition in the D.C. Court of Appeals seeking a review of the agency’s final
action on the petition. This case is being held in abeyance until the challenges
to the CAIR have been resolved. The outcome of this matter cannot be
predicted.
  National Ambient Air Quality
Standards
  On
December 21, 2005, the EPA announced proposed changes to the National Ambient
Air Quality Standards (NAAQS) for particulate matter. The EPA proposed to lower
the 24-hour standard for particulate matter less than 2.5 microns in diameter
(PM 2.5) from 65 micrograms per cubic meter to 35 micrograms per cubic meter. In
addition, the EPA proposed to establish a new 24-hour standard of 70 micrograms
per cubic meter for particulate matter that is between
2.5 and 10 microns in diameter (PM 2.5-10). The EPA also proposed to eliminate
the current standards for particulate matter less than 10 microns in diameter
(PM 10). On September 20, 2006, the EPA announced that it is finalizing the PM
2.5 NAAQS as proposed. In addition, the EPA decided not to establish a PM 2.5-10
NAAQS, and it is eliminating the annual PM 10 NAAQS, but the EPA is retaining
the 24-hour PM 10 NAAQS. These changes are not expected to result in designation
of any additional nonattainment areas in PEC’s or PEF’s service territories. On
December 18, 2006, environmental groups and 13 states filed a joint petition
with the D.C. Court of Appeals arguing that the EPA's new particulate matter
rule does not adequately restrict levels of particulate matter. The outcome of
this matter cannot be predicted.
  On March
12, 2008, the EPA announced changes to the NAAQS for ground-level ozone. The EPA
revised the 8-hour primary and secondary standards from 0.08 parts per million
to 0.075 parts per million. Depending on air quality improvements expected over
the next several years as current federal requirements are implemented,
additional nonattainment areas may be designated in PEC’s and PEF’s service
territories. Should additional nonattainment areas be designated in our service
territories, we may be required to install additional emission controls at some
of our facilities. The outcome of this matter cannot be predicted.
  Water
Quality
  1.
General
  As a
result of the operation of certain control equipment needed to address the air
quality issues outlined above, new wastewater streams may be generated at the
affected facilities. Integration of these new wastewater streams into the
existing wastewater treatment processes may result in permitting, construction
and treatment requirements imposed on the Utilities in the immediate and
extended future.
  2.
Section 316(b) of the Clean Water Act
  Section
316(b) of the Clean Water Act (Section 316(b)) requires cooling water intake
structures to reflect the best technology available for minimizing adverse
environmental impacts. The EPA promulgated a rule implementing Section 316(b) in
respect to existing power plants in July 2004. The July 2004 rule required
assessment of the baseline environmental effect of withdrawal of cooling water
and development of technologies and measures for reducing environmental effects
by certain percentages. Additionally, the rule authorized establishment of
alternative performance standards where the site-specific costs of achieving the
otherwise applicable standards would have been substantially greater than either
the benefits achieved or the costs considered by the EPA during the
rulemaking.
  Subsequent
to promulgation of the rule, a number of states, environmental groups and others
sought judicial review of the rule. On January 25, 2007, the U.S. Court of
Appeals for the Second Circuit issued an opinion and order remanding many
provisions of the rule to the EPA. On July 9, 2007, the EPA suspended the rule
pending further rulemaking, with the exception of the requirement that
permitting authorities establish best available technology
  79
 controls
for minimizing adverse environmental impact at existing cooling water intake
structures on a case-by-case, best professional judgment basis. On April 14,
2008, the U.S. Supreme Court agreed to review a portion of the U.S. Court of
Appeals decision and hear arguments related to whether the EPA is authorized to
compare costs with benefits in determining the “best technology available for
minimizing adverse environmental impact” at cooling water intake structures. As
a result of these recent developments, our plans and associated estimated costs
to comply with Section 316(b) will need to be reassessed and determined in
accordance with any revised or new implementing rule once it is established by
the EPA. Costs of compliance with a new implementing rule are expected to be
higher, and could be significantly higher, than estimated costs under the July
2004 rule. Our most recent cost estimates to comply with the July 2004
implementing rule were $60 million to $90 million, including $5 million to $10
million at PEC and $55 million to $80 million at PEF. The outcome of this matter
cannot be predicted.
  OTHER
ENVIRONMENTAL MATTERS
  Global Climate
Change
  The Kyoto
Protocol was adopted in 1997 by the United Nations to address global climate
change by reducing emissions of CO2 and other
greenhouse gases. The treaty went into effect on February 16, 2005. The United
States has not adopted the Kyoto Protocol. There are proposals and ongoing
studies at the state and federal levels, including the state
of Florida, to address global climate change that would regulate CO2 and other
greenhouse gases. See further discussion of the executive orders issued by the
governor of Florida to address reduction of greenhouse gas emissions under
“Other Matters – Regulatory Environment.”
  Reductions
in CO2
emissions to the levels specified by the Kyoto Protocol and some additional
proposals could be materially adverse to our financial position or results of
operations if associated costs of control or limitation cannot be recovered from
ratepayers. The cost impact of legislation or regulation to address global
climate change would depend on the specific legislation or regulation enacted
and cannot be determined at this time. We have articulated principles that we
believe should be incorporated into any global climate change policy. While the
outcome of this matter cannot be predicted, we are taking action on this
important issue as discussed under “Other Matters – Increasing Energy Demand.”
In addition to a report issued in 2006, we will issue an updated report on
global climate change in the second quarter of 2008, which further evaluates
this dynamic issue. While we participate in the development of a national
climate change policy framework, we will continue to actively engage others in
our region to develop consensus-based solutions, as we did with the Clean
Smokestacks Act.
  In a
decision issued July 15, 2005, the D.C. Court of Appeals denied petitions for
review filed by several states, cities and organizations seeking the regulation
by the EPA of CO2 emissions
from new automobiles under the Clean Air Act, holding that the EPA administrator
properly exercised his discretion in denying the request for regulation. The
U.S. Supreme Court agreed to hear the case and on April 2, 2007, it ruled that
the EPA has the authority under the Clean Air Act to regulate CO2 emissions
from new automobiles. On April 2, 2008, 18 states and 11 environmental groups
filed an action in the D. C. Circuit Court against the EPA Administrator seeking
an order requiring EPA to make a determination within 60 days of whether
greenhouse gas emissions endanger public health and welfare. The impact of these
developments cannot be predicted.
  NEW
ACCOUNTING STANDARDS
  See Note
2 for a discussion of the impact of new accounting standards.
  80
  PEC
  The
following MD&A and the information incorporated herein by reference contain
forward-looking statements that involve estimates, projections, goals,
forecasts, assumptions, risks and uncertainties that could cause actual results
or outcomes to differ materially from those expressed in the forward-looking
statements. Please review “Safe Harbor for Forward-Looking Statements” included
within this Form 10-Q and Item 1A, “Risk Factors” to the 2007 Form 10-K for a
discussion of the factors that may impact any such forward-looking statements
made herein.
  RESULTS OF
OPERATIONS
  This
information is incorporated herein by reference to “Results of Operations” in
Progress Energy’s MD&A, insofar as it relates to PEC.
  LIQUIDITY AND CAPITAL
RESOURCES
  This
information is incorporated herein by reference to “Liquidity and Capital
Resources” in Progress Energy’s MD&A, insofar as it relates to
PEC.
  Cash
provided by operating activities increased $209 million for the three months
ended March 31, 2008, when compared to the corresponding period in the prior
year. The increase in operating cash flow was primarily due to a $92 million
impact from increases in accounts payable and payables to affiliated companies;
$53 million due to income tax impacts; a $25 million impact due to lower
wholesale billings; and a $16 million impact from inventory, primarily due to
lower coal inventory purchases. The increase in accounts payable and payables to
affiliated companies was primarily driven by the timing of purchases and
payments to vendors and affiliates.
  Cash used
by investing activities increased $137 million for the three months ended March
31, 2008, when compared to the corresponding period in the prior year. The
increase in cash used in investing activities was primarily due to a $109
million increase in advances to affiliates and a $50 million decrease in net
proceeds from short-term investments included in available-for-sale securities
and other investments. Available-for-sale securities and other investments
include marketable debt securities and investments held in nuclear
decommissioning trusts. These impacts were partially offset by a $35 million
decrease in capital expenditures for utility property additions, primarily
driven by lower spending for compliance with the Clean Smokestacks
Act.
  Net cash
provided by financing activities was $164 million for the three months ended
March 31, 2008, compared to net cash used by financing activities of $26 million
for the three months ended March 31, 2007, for a net increase of $190 million.
The increase in cash provided by financing activities was due primarily to a
$325 million long-term debt issuance, partially offset by a $154 million
decrease related to advances from affiliates. PEC’s 2008 financing activities
are further described under Progress Energy’s MD&A, “Liquidity and Capital
Resources”.
  OFF-BALANCE SHEET
ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS
  PEC’s
off-balance sheet arrangements and contractual obligations are described
below.
  MARKET
RISK AND DERIVATIVES
  Under its
risk management policy, PEC may use a variety of instruments, including swaps,
options and forward contracts, to manage exposure to fluctuations in commodity
prices and interest rates. See Note 9 and Item 3, “Quantitative and Qualitative
Disclosures about Market Risk” of this Form 10-Q, for a discussion of market
risk and derivatives.
  CONTRACTUAL
OBLIGATIONS
  This
information is incorporated herein by reference to “Contractual Obligations” in
Progress Energy’s MD&A, insofar as it relates to PEC.
  81
  OTHER
MATTERS
  This
information is incorporated herein by reference to “Other Matters” in Progress
Energy’s MD&A, insofar as it relates to PEC.
  82
  PEF
  The
following MD&A and the information incorporated herein by reference contain
forward-looking statements that involve estimates, projections, goals,
forecasts, assumptions, risks and uncertainties that could cause actual results
or outcomes to differ materially from those expressed in the forward-looking
statements. Please review “Safe Harbor for Forward-Looking Statements” included
within this Form 10-Q and Item 1A, “Risk Factors” to the 2007 Form 10-K for a
discussion of the factors that may impact any such forward-looking statements
made herein.
  Other
than as discussed below, the information called for by Item 2 is omitted
pursuant to Instruction H(2)(c) to Form 10-Q (Omission of Information by Certain
Wholly Owned Subsidiaries).
  RESULTS OF
OPERATIONS
  This
information is incorporated herein by reference to “Results of Operations” in
Progress Energy’s MD&A, insofar as it relates to PEF.
  LIQUIDITY AND CAPITAL
RESOURCES
  This
information is incorporated herein by reference to “Liquidity and Capital
Resources” in Progress Energy’s MD&A, insofar as it relates to
PEF.
  Cash
provided by operating activities decreased $39 million for the three months
ended March 31, 2008, when compared to the corresponding period in the prior
year. The decrease was primarily due to an $82 million decrease in the recovery
of fuel costs, a $32 million increase in NOx and SO2 emission
allowance purchases, and a $10 million decrease from accounts receivable and
receivables from affiliated companies. These impacts were partially offset by a
$90 million increase from accounts payable and payables to affiliated companies
primarily driven by the timing of purchases and payments to vendors and
affiliates.
  Cash used
in investing activities increased $7 million for the three months ended March
31, 2008, when compared to the corresponding period in the prior year. The
increase in cash used in investing activities was primarily due to a $185
million increase in capital expenditures for utility property additions,
primarily due to a $137 million increase in environmental compliance spending.
This impact was partially offset by a $149 million decrease in advances to
affiliates and a $23 million decrease in nuclear fuel additions.
 
 Net cash
provided by financing activities was $14 million for the three months ended
March 31, 2008, compared to net cash used by financing activities of $36 million
for the three months ended March 31, 2007, for a net increase of $50 million.
The increase in cash provided by financing activities was due primarily to a
$131 million change in advances from affiliates, partially offset by the payment
at maturity of $80 million in first mortgage bonds. PEF’s 2008 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 9 and Item 3, “Quantitative and Qualitative
Disclosures about Market Risk” of this Form 10-Q, for a discussion of market
risk and derivatives.
  CONTRACTUAL
OBLIGATIONS
  This
information is incorporated herein by reference to “Contractual Obligations” in
Progress Energy’s MD&A, insofar as it relates to PEF.
  83
  OTHER
MATTERS
  This
information is incorporated herein by reference to “Other Matters” in Progress
Energy’s MD&A, insofar as it relates to PEF.
  84
  ITEM
3.                      QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT MARKET RISK
  We are
exposed to various risks related to changes in market conditions. Market risk
represents the potential loss arising from adverse changes in market rates and
prices. We have a risk management committee that includes senior executives from
various business groups. The risk management committee is responsible for
administering risk management policies and monitoring compliance with those
policies by all subsidiaries. Under our risk policy, we may use a variety of
instruments, including swaps, options and forward contracts, to manage exposure
to fluctuations in commodity prices and interest rates. Such instruments contain
credit risk to the extent that the counterparty fails to perform under the
contract. We mitigate such risk by performing credit reviews using, among other
things, publicly available credit ratings of such counterparties (See Note
9).
  The
following disclosures about market risk contain forward-looking statements that
involve estimates, projections, goals, forecasts, assumptions, risks and
uncertainties that could cause actual results or outcomes to differ materially
from those expressed in the forward-looking statements. Please review Item 1A,
“Risk Factors” to the 2007 Form 10-K and “Safe Harbor for Forward-Looking
Statements” included within this Form 10-Q for a discussion of the factors that
may impact any such forward-looking statements made herein.
  Certain
market risks are inherent in our financial instruments, which arise from
transactions entered into in the normal course of business. Our primary
exposures are changes in interest rates with respect to our long-term debt and
commercial paper, fluctuations in the return on marketable securities with
respect to our nuclear decommissioning trust funds, changes in the market value
of CVOs, and changes in energy-related commodity prices.
  These
financial instruments are held for purposes other than trading. The risks
discussed below do not include the price risks associated with nonfinancial
instrument transactions and positions associated with our operations, such as
purchase and sales commitments and inventory.
  PROGRESS
ENERGY
  Other
than described below, the various risks that we are exposed to have not
materially changed since December 31, 2007.
  INTEREST RATE
RISK
  Our
exposure to changes in interest rates from fixed rate and variable rate
long-term debt at March 31, 2008, has changed from December 31, 2007. The total
notional amount of fixed rate long-term debt at March 31, 2008, was $8.2
billion, with an average interest rate of 5.94% and fair market value of $8.5
billion. The total notional amount of fixed rate long-term debt at December 31,
2007, was $7.9 billion, with an average interest rate of 6.20% and fair market
value of $8.2 billion. The total notional amount of variable rate long-term debt
at March 31, 2008, was $1.4 billion, with an average interest rate of 4.27% and
fair market value of $1.4 billion. The total notional amount of variable rate
long-term debt at December 31, 2007, was $1.4 billion, with an average interest
rate of 4.80% and fair market value of $1.4 billion.
  In
addition to our variable rate long-term debt, we typically have commercial paper
and/or loans outstanding under our RCA facilities, which are also exposed to
floating interest rates. At March 31, 2008, and December 31, 2007, approximately
16 percent of consolidated debt was in floating rate mode, including interest
rate swaps.
  From time
to time, we use interest rate derivative instruments to adjust the mix between
fixed and floating rate debt in our debt portfolio, to mitigate our exposure to
interest rate fluctuations associated with certain debt instruments, and to
hedge interest rates with regard to future fixed rate debt
issuances.
  The
notional amounts of interest rate derivatives are not exchanged and do not
represent exposure to credit loss. In the event of default by a counterparty,
the exposure in the transaction is the cost of replacing the agreements at
current market rates. We only enter into interest rate derivative agreements
with banks with credit ratings of single A or better.
  85
 We use a
number of models and methods to determine interest rate risk exposure and fair
value of derivative positions. For reporting purposes, fair values and exposures
of derivative positions are determined as of the end of the reporting period
using the Bloomberg Financial Markets system.
  In
accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging
Activities” (SFAS No. 133), interest rate derivatives that qualify as hedges are
separated into one of two categories, cash flow hedges or fair value hedges.
Cash flow hedges are used to reduce exposure to changes in cash flow due to
fluctuating interest rates. Fair value hedges are used to reduce exposure to
changes in fair value due to interest rate changes.
  The
following tables summarize the terms, fair market values and exposures of our
interest rate derivative instruments.
  CASH FLOW
HEDGES
  At March
31, 2008, PEF had $200 million notional of pay-fixed forward starting swaps to
hedge cash flow risk with regard to future financing transactions and at
December 31, 2007, PEC had $200 million notional of pay-fixed forward starting
swaps to hedge cash flow risk with regard to future financing transactions.
Under terms of these swap agreements, we will pay a fixed rate and receive a
floating rate based on the 3-month London Inter Bank Offering Rate (LIBOR). The
Parent had no open interest rate cash flow hedges at March 31, 2008, and
December 31, 2007.
  Cash
      Flow Hedges (dollars in
      millions)
              Notional
                Amount
              Pay
              Receive
      (a)
              Fair
      Value
              Exposure
      (b)PECRisk hedged at March
      31, 2008
              NoneRisk hedged at
      December 31, 2007Anticipated
      10-year debt issue (c)
              $100
              5.32%
              3-month
      LIBOR
              $(5)
              $(2)Anticipated
      30-year debt issue (d)
              100
              5.50%
              3-month
      LIBOR
              (7)
              (4)Total
              $200
              5.41%
              
              $(12)
              $(6)PEFRisk hedged at March
      31, 2008Anticipated
      10-year debt issue (e)
              $100
              4.52%
              3-month
      LIBOR
              $(3)
              $(2)Anticipated
      30-year debt issue (f)
              100
              4.92%
              3-month
      LIBOR
              (4)
              (4)Total
              $200
              4.72%
              
              $(7)
              $(6)Risk hedged at
      December 31, 2007:
              None
 (a)
              3-month
      LIBOR rate was 2.69% at March 31, 2008, and 4.70% at December 31,
      2007.
 (b)
              Exposure
      indicates change in value due to 25 basis point unfavorable shift in
      interest rates.
 (c)
              Anticipated
      10-year debt issue hedges were terminated on March 10, 2008, in
      conjunction with PEC’s issuance of $325 million 6.30% First Mortgage
      Bonds.
 (d)
              Anticipated
      30-year debt issue hedges were terminated on March 10, 2008, in
      conjunction with PEC’s issuance of $325 million 6.30% First Mortgage
      Bonds.
 (e)
              Anticipated
      10-year debt issue hedge matures on June 30, 2018, and requires mandatory
      cash settlement on June 30, 2008.
 (f)
              Anticipated
      30-year debt issue hedge matures on June 30, 2038, and requires mandatory
      cash settlement on June 30, 2008.
 
 On
January 8, 2008, PEF entered into a 10-year $100 million notional forward
starting swap and a 30-year $100 million notional forward starting swap to
mitigate exposure to interest rate risk in anticipation of future debt
issuances. On May 1, 2008, PEF entered into a $50 million notional 10-year
forward starting swap and a $100
  86
 million
notional 30-year forward starting swap to mitigate exposure to interest rate
risk in anticipation of future debt issuances.
  MARKETABLE SECURITIES PRICE
RISK
  At March
31, 2008, and December 31, 2007, the fair value of our nuclear decommissioning
trust funds was $1.313 billion and $1.384 billion, respectively, including $771
million and $804 million, respectively, for PEC and $542 million and $580
million, respectively, for PEF. The accounting for nuclear decommissioning
recognizes that the Utilities’ regulated electric rates provide for recovery of
these costs net of any trust fund earnings, and, therefore, fluctuations in
trust fund marketable security returns do not affect earnings.
  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, 2008, and December 31, 2007, the
fair value of CVOs was $34 million. 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, 2008, market price would result in a $3 million
increase in the fair value of the CVOs.
  COMMODITY PRICE
RISK
  We are
exposed to the effects of market fluctuations in the price of natural gas, coal,
fuel oil, electricity and other energy-related products marketed and purchased
as a result of our ownership of energy-related assets. Our exposure to these
fluctuations is significantly limited by the cost-based regulation of the
Utilities. Each state commission allows electric utilities to recover certain of
these costs through various cost-recovery clauses to the extent the respective
commission determines that such costs are prudent. Therefore, while there may be
a delay in the timing between when these costs are incurred and when these costs
are recovered from the ratepayers, changes from year to year have no material
impact on operating results. In addition, most of our long-term power sales
contracts shift substantially all fuel price risk to the purchaser.
  Most of
our commodity contracts are not derivatives pursuant to SFAS No. 133 or qualify
and are elected as normal purchases or sales pursuant to SFAS No. 133.
Therefore, such contracts are not recorded at fair value.
  We
perform sensitivity analyses to estimate our exposure to the market risk of our
derivative commodity instruments that are not eligible for recovery from
ratepayers. At March 31, 2008, we did not have any derivative commodity
instruments not eligible for recovery from ratepayers.
  See Note
9 for additional information with regard to our commodity contracts and use of
derivative financial instruments.
  DISCONTINUED
OPERATIONS
  On
January 8, 2007, we entered into derivative contracts to hedge economically a
portion of our 2007 synthetic fuels cash flow exposure to the risk of rising oil
prices. These contracts ended on December 31, 2007, and were settled for cash on
January 8, 2008, with no material impact to 2008 earnings. At December 31, 2007,
the $234 million fair value of these contracts was included in receivables,
net on the Consolidated Balance Sheet. See Note 9A for additional discussion
related to our commodity derivatives.
  ECONOMIC
DERIVATIVES
  Derivative
products, primarily electricity and natural gas contracts, may be entered into
from time to time for economic hedging purposes. While management believes the
economic hedges mitigate exposures to fluctuations in commodity prices, these
instruments are not designated as hedges for accounting purposes and are
monitored consistent with trading positions. We manage open positions with
strict policies that limit our exposure to market risk and require daily
reporting to management of potential financial exposures.
  The
Utilities have derivative instruments related to their exposure to price
fluctuations on fuel oil and natural gas purchases. These instruments receive
regulatory accounting treatment. Unrealized gains and losses are recorded in
regulatory liabilities and regulatory assets on the Balance Sheets,
respectively, until the contracts are settled. Once settled, any realized gains
or losses are passed through the fuel clause. During the quarters ended March
31, 2008
  87
 and 2007,
PEC recorded a net realized gain of less than $1 million. During the quarters
ended March 31, 2008 and 2007, PEF recorded a net realized gain of $16 million
and a net realized loss of $17 million, respectively.
  The
December 31, 2007 balances presented below reflect the retrospective adoption of
FASB Staff Position No. FIN 39-1, “An Amendment of FIN 39, Offsetting of Amounts
Related to Certain Contracts” (See Note 2).
  At March
31, 2008, the fair value of PEC’s commodity derivative instruments was recorded
as a $13 million short-term derivative asset position included in prepayments
and other current assets and $36 million long-term derivative asset position
included in other assets and deferred debits on the PEC Consolidated Balance
Sheet. At December 31, 2007, the fair value of such instruments were recorded as
a $19 million long-term derivative asset position included in other assets and
deferred debits and a $4 million short-term derivative liability included in
other current liabilities on the PEC Consolidated Balance Sheet. PEC had no cash
collateral position at March 31, 2008 or December 31, 2007.
  At March
31, 2008, the fair value of PEF’s commodity derivative instruments was recorded
as a $204 million short-term derivative asset position included in current
derivative assets, a $174 million long-term derivative asset position included
in derivative assets, a $4 million short-term liability position included in
derivative liabilities, and a $5 million long-term derivative liability position
included in other liabilities and deferred credits on the PEF Balance Sheet. At
December 31, 2007, the fair value of such instruments were recorded as a $83
million short-term derivative asset position included in current derivative
assets, a $100 million long-term derivative asset position included in
derivative assets, a $38 million short-term liability position included in
derivative liabilities, and a $9 million long-term derivative liability position
included in other liabilities and deferred credits on the PEF Balance Sheet. PEF
had a $51 million cash collateral liability at March 31, 2008, included in other
current liabilities on the PEF Balance Sheet, and no cash collateral position at
December 31, 2007.
  CASH
FLOW HEDGES
  PEC
designates a portion of commodity derivative instruments as cash flow hedges
under SFAS No. 133. The objective for holding these instruments is to hedge
exposure to market risk associated with fluctuations in the price of power for
our forecasted sales. Realized gains and losses are recorded net in operating
revenues. At March 31, 2008 and December 31, 2007, neither we nor the Utilities
had material outstanding positions in such contracts. The ineffective portion of
commodity cash flow hedges was not material to our or the Utilities’ results of
operations for the three months ended March 31, 2008 and 2007.
  At March
31, 2008 and December 31, 2007, the amount recorded in our or PEC’s accumulated
other comprehensive income related to commodity cash flow hedges was not
material and PEF had no amount recorded in accumulated other comprehensive
income related to commodity cash flow hedges.
  PEC
  The
information required by this item is incorporated herein by reference to the
“Quantitative and Qualitative Disclosures about Market Risk” discussed above
insofar as it relates to PEC.
  PEC has
certain market risks inherent in its financial instruments, which arise from
transactions entered into in the normal course of business. PEC’s primary
exposures are changes in interest rates with respect to long-term debt and
commercial paper, fluctuations in the return on marketable securities with
respect to its nuclear decommissioning trust funds, and changes in energy
related commodity prices. Other than as discussed above, PEC’s exposure to these
risks has not materially changed since March 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).
  88
  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, 2008, that has materially affected, or is reasonably
likely to materially affect, our internal control over financial
reporting.
 ITEM 4.TCONTROLS
AND PROCEDURES
 PEC
  Pursuant
to the Securities Exchange Act of 1934, PEC carried out an evaluation, with the
participation of its management, including PEC’s Chief Executive Officer and
Chief Financial Officer, of the effectiveness of PEC’s disclosure controls and
procedures (as defined under the Securities Exchange Act of 1934) as of the end
of the period covered by this report. Based upon that evaluation, PEC’s Chief
Executive Officer and Chief Financial Officer concluded that its disclosure
controls and procedures are effective to ensure that information required to be
disclosed by PEC in the reports that it files or submits under the Exchange Act,
is recorded, processed, summarized and reported within the time periods
specified in the SEC's rules and forms, and that such information is accumulated
and communicated to PEC’s management, including the Chief Executive Officer and
Chief Financial Officer, as appropriate, to allow timely decisions regarding
required disclosure.
   There has
been no change in PEC’s internal control over financial reporting during the
quarter ended March 31, 2008, that has materially affected, or is reasonably
likely to materially affect, its internal control over financial
reporting.
  PEF
  Pursuant
to the Securities Exchange Act of 1934, PEF carried out an evaluation, and with
the participation of its management, including PEF’s Chief Executive Officer and
Chief Financial Officer, of the effectiveness of PEF’s disclosure controls and
procedures (as defined under the Securities Exchange Act of 1934) as of the end
of the period covered by this report. Based upon that evaluation, PEF’s Chief
Executive Officer and Chief Financial Officer concluded that its disclosure
controls and procedures are effective to ensure that information required to be
disclosed by PEF in the reports that it files or submits under the Exchange Act,
is recorded, processed, summarized and reported within the time periods
specified in the SEC's rules and forms, and that such information is accumulated
and communicated to PEF’s management, including the Chief Executive Officer and
Chief Financial Officer, as appropriate, to allow timely decisions regarding
required disclosure.
  There has
been no change in PEF’s internal control over financial reporting during the
quarter ended March 31, 2008, that has materially affected, or is reasonably
likely to materially affect, its internal control over financial
reporting.
  89
  PART
II.  OTHER INFORMATION
 
 ITEM
1.                      LEGAL
PROCEEDINGS
  Legal
aspects of certain matters are set forth in PART I, Item 1 (See Note
13C).
  ITEM 1A.  RISK FACTORS
  In
addition to the other information set forth in this report, you should carefully
consider the factors discussed in Part I, Item 1A. Risk Factors to the 2007 Form
10-K, which could materially affect our business, financial condition or future
results. The risks described in the 2007 Form 10-K are not the only risks facing
us. Additional risks and uncertainties not currently known to us or that we
currently deem to be immaterial also may materially adversely affect our
business, financial condition and/or operating results.
  With the
2008 divestiture of Terminals and Coal Mining, we are no longer subject to
operational and financial risks from operating nonregulated businesses as
disclosed in the 2007 Form 10-K.
  
 ITEM
2.                     UNREGISTERED SALE OF EQUITY
SECURITIES AND USE OF PROCEEDS
  RESTRICTED
STOCK UNIT AWARD PAYOUTS
  (a)
              Securities
      Delivered. On January 2, 2008, January 15, 2008 and January 24,
      2008, 91 shares, 4,178 shares and 296 shares, respectively, of our common
      stock were delivered to certain former employees pursuant to the terms of
      the Progress Energy 2002 Equity Incentive Plan (EIP), which was approved
      by Progress Energy’s shareholders on May 8, 2002. Additionally, on March
      20, 2008, 170,516 shares 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 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.
 
 PERFORMANCE
SHARE SUB-PLAN AWARD PAYOUTS
  (a)
              Securities
      Delivered. On March 24, 2008, 360,674 shares of our common stock
      were delivered to 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.
 
 90
 (c)
              Consideration.
      The performance share awards were granted to provide an incentive to the
      former employees to exert their utmost efforts on Progress Energy’s behalf
      and thus enhance our performance while aligning the employees’ interest
      with those of our shareholders.
 
 (d)
              Exemption from
      Registration Claimed. The common shares described in this Item were
      delivered pursuant to a broad-based involuntary, non-contributory employee
      benefit plan, and thus did not involve an offer to sell or sale of
      securities within the meaning of Section 2(3) of the Securities Act of
      1933. Receipt of the shares of our common stock required no investment
      decision on the part of the
recipient.
 
 ISSUER
PURCHASES OF EQUITY SECURITIES FOR FIRST QUARTER OF 2008
  Period
              (a)
                Total
      Number
                of
      Shares
                (or
      Units)
                Purchased
      (1)(2)
              (b)
                Average
                Price
      Paid
                Per
      Share
                (or
      Unit)
              (c)
                Total
      Number of
                Shares
      (or Units)
                Purchased
      as Part of
                Publicly
      Announced
                Plans
      or Programs (1)
              (d)
                Maximum
      Number (or
                Approximate
      Dollar
                Value)
      of Shares (or
                Units)
      that May Yet Be
                Purchased
      Under the
                Plans
      or Programs (1)January
      1 – January 31
              429,378
              $46.2555
              N/A
              N/AFebruary
      1 - February 29
              70,000
              43.9054
              N/A
              N/AMarch
      1 - March 31
              –
              –
              N/A
              N/ATotal
              499,378
              $45.9261
              N/A
              N/A
 
 (1)
              At
      March 31, 2008, Progress Energy did not have any publicly announced plans
      or programs to purchase shares of its common
  stock.
 (2)
              The
      plan administrator purchased 499,378 shares of our common stock in
      open-market transactions to meet share delivery obligations under our
      401(k).
  ITEM
5.                   OTHER
INFORMATION
  CONDENSED CONSOLIDATING
STATEMENTS FOR THE YEARS ENDED DECEMBER 31, 2007, 2006 AND
2005
 
 For
informational purposes, we have corrected an error in the presentation of the
condensed consolidating Statements of Income previously reported in Note 23 in
the 2007 Form 10-K. The error related to the line items affiliate revenues and
discontinued operations, net of tax in the Subsidiary Guarantor and the Other
columns. Specifically, certain affiliate revenues of discontinued Terminals
operations were incorrectly included in continuing operations. This resulted in
misclassifications between income from continuing operations and discontinued
operations, net of tax in the Subsidiary Guarantor column in the condensed
consolidating Statements of Income for the years ended December 31, 2007, 2006
and 2005. There were equal and offsetting errors in the Other column, with no
impact to the Parent or Progress Energy, Inc. columns. This correction is
limited to the Subsidiary Guarantor and the Other columns in the condensed
consolidating Statements of Income in Note 23 in the 2007 Form 10-K and does not
affect Progress Energy’s Consolidated Statements of Income, Consolidated Balance
Sheets or Consolidated Statements of Cash Flows. We will prospectively present
restated consolidating financial information the next time we issue our annual
consolidated financial statements.
 91
  The
following schedules present the specific line item amounts in Note 23 in the
2007 Form 10-K that have been restated as a result of this
correction:
  
 Condensed
      Consolidating Statement of Income
                Year
      ended December 31, 2007(in
      millions)
              
              Parent
              
              
              Subsidiary
                Guarantor
              
              
              Other
              
              
              Progress
                Energy,
      Inc.As
      originally reportedAffiliate
      revenues
              
              $
              –
              
              
              $
              89
              
              
              $
              (89
              )
              
              $
              –Total
      operating revenues
              
              
              –
              
              
              
              4,857
              
              
              
              4,296
              
              
              
              9,153Operating
      (loss) income
              
              
              (10
              )
              
              
              679
              
              
              
              877
              
              
              
              1,546(Loss)
      income from continuing operations before income tax, equity in earnings of
                consolidated
      subsidiaries and minority interest
              
              
              (186
              )
              
              
              528
              
              
              
              694
              
              
              
              1,036Income
      (loss) from continuing operations
              
              
              489
              
              
              
              402
              
              
              
              (198
              )
              
              
              693Discontinued
      operations, net of tax
              
              
              15
              
              
              
              (59
              )
              
              
              (145
              )
              
              
              (189
              )As
      restatedAffiliate
      revenues
              
              $
              –
              
              
              $
              –
              
              
              $
              –
              
              
              $
              –Total
      operating revenues
              
              
              –
              
              
              
              4,768
              
              
              
              4,385
              
              
              
              9,153Operating
      (loss) income
              
              
              (10
              )
              
              
              590
              
              
              
              966
              
              
              
              1,546(Loss)
      income from continuing operations before income tax, equity in earnings of
                consolidated
      subsidiaries and minority interest
              
              
              (186
              )
              
              
              439
              
              
              
              783
              
              
              
              1,036Income
      (loss) from continuing operations
              
              
              489
              
              
              
              313
              
              
              
              (109
              )
              
              
              693Discontinued
      operations, net of tax
              
              
              15
              
              
              
              30
              
              
              
              (234
              )
              
              
              (189
              )
 
 Condensed
      Consolidating Statement of Income
                Year
      ended December 31, 2006(in
      millions)
              
              Parent
              
              
              Subsidiary
                Guarantor
              
              
              Other
              
              
              Progress
                Energy,
      Inc.As
      originally reportedAffiliate
      revenues
              
              $
              –
              
              
              $
              41
              
              
              $
              (41
              )
              
              $
              –Total
      operating revenues
              
              
              –
              
              
              
              4,678
              
              
              
              4,046
              
              
              
              8,724Operating
      (loss) income
              
              
              (14
              )
              
              
              657
              
              
              
              844
              
              
              
              1,487(Loss)
      income from continuing operations before income tax, equity in earnings of
                consolidated
      subsidiaries and minority interest
              
              
              (323
              )
              
              
              530
              
              
              
              699
              
              
              
              906Income
      (loss) from continuing operations
              
              
              579
              
              
              
              340
              
              
              
              (368
              )
              
              
              551Discontinued
      operations, net of tax
              
              
              (8
              )
              
              
              359
              
              
              
              (331
              )
              
              
              20As
      restatedAffiliate
      revenues
              
              $
              –
              
              
              $
              –
              
              
              $
              –
              
              
              $
              –Total
      operating revenues
              
              
              –
              
              
              
              4,637
              
              
              
              4,087
              
              
              
              8,724Operating
      (loss) income
              
              
              (14
              )
              
              
              616
              
              
              
              885
              
              
              
              1,487(Loss)
      income from continuing operations before income tax, equity in earnings of
                consolidated
      subsidiaries and minority interest
              
              
              (323
              )
              
              
              489
              
              
              
              740
              
              
              
              906Income
      (loss) from continuing operations
              
              
              579
              
              
              
              299
              
              
              
              (327
              )
              
              
              551Discontinued
      operations, net of tax
              
              
              (8
              )
              
              
              400
              
              
              
              (372
              )
              
              
              20
  92
 
 Condensed
      Consolidating Statement of Income
                Year
      ended December 31, 2005(in
      millions)
              
              Parent
              
              
              Subsidiary
                Guarantor
              
              
              Other
              
              
              Progress
                Energy,
      Inc.As
      originally reportedAffiliate
      revenues
              
              $
              –
              
              
              $
              188
              
              
              $
              (188
              )
              
              $
              –Total
      operating revenues
              
              
              –
              
              
              
              4,144
              
              
              
              3,804
              
              
              
              7,948Operating
      (loss) income
              
              
              (16
              )
              
              
              664
              
              
              
              740
              
              
              
              1,388(Loss)
      income from continuing operations before income tax, equity in earnings of
                consolidated
      subsidiaries and minority interest
              
              
              (255
              )
              
              
              500
              
              
              
              580
              
              
              
              825Income
      (loss) from continuing operations
              
              
              693
              
              
              
              400
              
              
              
              (570
              )
              
              
              523Discontinued
      operations, net of tax
              
              
              4
              
              
              
              (26
              )
              
              
              195
              
              
              
              173As
      restatedAffiliate
      revenues
              
              $
              –
              
              
              $
              –
              
              
              $
              –
              
              
              $
              –Total
      operating revenues
              
              
              –
              
              
              
              3,956
              
              
              
              3,992
              
              
              
              7,948Operating
      (loss) income
              
              
              (16
              )
              
              
              476
              
              
              
              928
              
              
              
              1,388(Loss)
      income from continuing operations before income tax, equity in earnings of
                consolidated
      subsidiaries and minority interest
              
              
              (255
              )
              
              
              312
              
              
              
              768
              
              
              
              825Income
      (loss) from continuing operations
              
              
              693
              
              
              
              212
              
              
              
              (382
              )
              
              
              523Discontinued
      operations, net of tax
              
              
              4
              
              
              
              162
              
              
              
              7
              
              
              
              173
  QUARTERLY FINANCIAL
      DATA FOR 2007 AND 2006  We have
corrected an error in the presentation of the unaudited summarized financial
data previously reported for Progress Energy in Note 24 in the 2007 Form 10-K.
Specifically, the Progress Energy quarterly data reported for 2007 and 2006
contained misclassifications between income from continuing operations and
income from discontinued operations relating to the impacts of quarterly tax
levelization adjustments (See Note 1B). When the synthetic fuels businesses were
reclassified to discontinued operations in the fourth quarter of 2007 (See Note
3A), the impacts of the quarterly tax levelization adjustments associated with
the synthetic fuels tax credits were not also reclassified to discontinued
operations. This correction is limited to amounts reported for Progress Energy
only in Note 24 in the 2007 Form 10-K and does not affect the information
presented in Note 24 for PEC and PEF. This correction does not affect our
Consolidated Statements of Income for 2007 or 2006, as the quarterly tax
levelization adjustments net to zero on an annual basis. In addition, this
correction does not impact any previously filed Form 10-Q as the synthetic fuels
businesses were first reclassified to discontinued operations in the fourth
quarter of 2007.
  93
 The
following schedules present specific line item amounts in Note 24 in the 2007
Form 10-K that have been restated as a result of this
correction:
  
 Progress
      Energy(in
      millions except per share data)
                
                First
                
                
                Second
                
                
                Third
                
                
                Fourth2007As
      originally reportedIncome
      from continuing operations
                
                $
                159
                
                
                $
                106
                
                
                $
                327
                
                
                $
                101Common
      stock dataBasic
      earnings per common shareIncome
      from continuing operations
                
                
                0.63
                
                
                
                0.42
                
                
                
                1.27
                
                
                
                0.39Diluted
      earnings per common shareIncome
      from continuing operations
                
                
                0.62
                
                
                
                0.41
                
                
                
                1.27
                
                
                
                0.39As
      restatedIncome
      from continuing operations
                
                
                149
                
                
                
                138
                
                
                
                311
                
                
                
                95Common
      stock dataBasic
      earnings per common shareIncome
      from continuing operations
                
                
                0.59
                
                
                
                0.54
                
                
                
                1.21
                
                
                
                0.37Diluted
      earnings per common shareIncome
      from continuing operations
                
                
                0.59
                
                
                
                0.54
                
                
                
                1.21
                
                
                
                0.372006As
      originally reportedIncome
      from continuing operations
                
                $
                67
                
                
                $
                110
                
                
                $
                268
                
                
                $
                106Common
      stock dataBasic
      earnings per common shareIncome
      from continuing operations before cumulative effect of change
      in accounting principle
                
                
                0.27
                
                
                
                0.44
                
                
                
                1.07
                
                
                
                0.42Diluted
      earnings per common shareIncome
      from continuing operations before cumulative effect of change
      in accounting principle
                
                
                0.27
                
                
                
                0.44
                
                
                
                1.07
                
                
                
                0.42As
      restatedIncome
      from continuing operations
                
                
                85
                
                
                
                112
                
                
                
                246
                
                
                
                108Common
      stock dataBasic
      earnings per common shareIncome
      from continuing operations
                
                
                0.34
                
                
                
                0.45
                
                
                
                0.98
                
                
                
                0.43Diluted
      earnings per common shareIncome
      from continuing operations
                
                
                0.34
                
                
                
                0.45
                
                
                
                0.98
                
                
                
                0.43
 94
 ITEM
      6.
              EXHIBITS
  (a)
              Exhibits
 
 Exhibit Number
              Description
              Progress
                Energy
              PEC
              PEF10(a)
              Executive
      and Key Manager 2008 Performance Share Sub-Plan, effective as of March 18,
      2008, Exhibit A to the 2007 Equity Incentive Plan
              X
              X
              X10(b)
              Form
      of Restricted Stock Unit Agreement as of March 18, 2008
              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
  95
 
 SIGNATURES
  Pursuant
to requirements of the Securities Exchange Act of 1934, the registrant has duly
caused this report to be signed on its behalf by the undersigned thereunto duly
authorized.
  PROGRESS ENERGY,
      INC.CAROLINA POWER &
      LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS,
  INC.FLORIDA POWER
      CORPORATION d/b/a PROGRESS ENERGY FLORIDA, INC.Date:
      May
      9, 2008
              (Registrants)By: /s/ Peter M. Scott
      IIIPeter
      M. Scott IIIExecutive
      Vice President and Chief Financial OfficerBy: /s/ Jeffrey M.
      StoneJeffrey
      M. StoneChief
      Accounting Officer and ControllerProgress
      Energy, Inc.Chief
      Accounting OfficerCarolina
      Power & Light Company d/b/a Progress Energy Carolinas,
      Inc.Florida
      Power Corporation d/b/a Progress Energy Florida,
  Inc.
  96