**UNITED
      STATES SECURITIES AND EXCHANGE COMMISSION**


**Washington,
      D. C. 20549**





**FORM
      10-Q**


**(Mark
      One)**


**[X]
      QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE**


**SECURITIES
      EXCHANGE ACT OF 1934**





**For
      the
      quarterly period ended September 30, 2006**





**OR**





**[
      ]
      TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE**


**SECURITIES
      EXCHANGE ACT OF 1934**





**For
                the transition period from**
            
            **to**





**Commission**
            **Registrant;
                State of Incorporation;**
            **I.R.S.
                Employer****File
                Number**
            **Address;
                and Telephone Number**
            **Identification
                No.****333-21011**
            **FIRSTENERGY
                CORP.**
            **34-1843785****(An
                Ohio Corporation)****76
                South Main Street****Akron,
                OH 44308****Telephone
                (800)736**-**3402****1-2578**
            **OHIO
                EDISON COMPANY**
            **34-0437786****(An
                Ohio Corporation)****c/o
                FirstEnergy Corp.****76
                South Main Street****Akron,
                OH 44308****Telephone
                (800)736**-**3402****1-2323**
            **THE
                CLEVELAND ELECTRIC ILLUMINATING COMPANY**
            **34-0150020****(An
                Ohio Corporation)****c/o
                FirstEnergy Corp.****76
                South Main Street****Akron,
                OH 44308****Telephone
                (800)736**-**3402****1-3583**
            **THE
                TOLEDO EDISON COMPANY**
            **34-4375005****(An
                Ohio Corporation)****c/o
                FirstEnergy Corp.****76
                South Main Street****Akron,
                OH 44308****Telephone
                (800)736**-**3402****1-3491**
            **PENNSYLVANIA
                POWER COMPANY**
            **25-0718810****(A
                Pennsylvania Corporation)****c/o
                FirstEnergy Corp.****76
                South Main Street****Akron,
                OH 44308****Telephone
                (800)736**-**3402****1-3141**
            **JERSEY
                CENTRAL POWER & LIGHT COMPANY**
            **21-0485010****(A
                New
                Jersey Corporation)****c/o
                FirstEnergy Corp.****76
                South Main Street****Akron,
                OH 44308****Telephone
                (800)736**-**3402****1-446**
            **METROPOLITAN
                EDISON COMPANY**
            **23-0870160****(A
                Pennsylvania Corporation)****c/o
                FirstEnergy Corp.****76
                South Main Street****Akron,
                OH 44308****Telephone
                (800)736**-**3402****1-3522**
            **PENNSYLVANIA
                ELECTRIC COMPANY**
            **25-0718085****(A
                Pennsylvania Corporation)****c/o
                FirstEnergy Corp.****76
                South Main Street****Akron,
                OH 44308****Telephone
                (800)736**-**3402**





Indicate
      by check
      mark whether each of the registrants (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
      registrant was required to file such reports), and (2) has been subject to
      such filing requirements for the past 90 days.





Yes (X) No (  )





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





Large
                Accelerated Filer(X)
            FirstEnergy
                Corp.Accelerated
                Filer( )
            N/ANon-accelerated
                Filer(X)
            Ohio
                Edison
                Company, The Cleveland Electric Illuminating Company, The Toledo
                Edison
                Company, Pennsylvania Power Company, Jersey Central Power & Light
                Company, Metropolitan Edison Company, and Pennsylvania Electric
                Company




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





Yes (
      ) No (X)





Indicate
      the number
      of shares outstanding of each of the issuer's classes of common stock, as of
      the
      latest practicable date:





**OUTSTANDING****CLASS**
            **AS
                OF OCTOBER 31, 2006**FirstEnergy
                Corp., $.10 par value
            319,205,517Ohio
                Edison
                Company, no par value
            80The
                Cleveland
                Electric Illuminating Company, no par value
            79,590,689The
                Toledo
                Edison Company, $5 par value
            39,133,887Pennsylvania
                Power Company, $30 par value
            6,290,000Jersey
                Central
                Power & Light Company, $10 par value
            15,371,270Metropolitan
                Edison Company, no par value
            859,500Pennsylvania
                Electric Company, $20 par value
            5,290,596





FirstEnergy
      Corp. is
      the sole holder of Ohio Edison Company, The Cleveland Electric Illuminating
      Company, The Toledo Edison Company, Jersey Central Power & Light Company,
      Metropolitan Edison Company and Pennsylvania Electric Company common stock.
      Ohio
      Edison Company is the sole holder of Pennsylvania Power Company common stock.





This
      combined Form
      10-Q is separately filed by FirstEnergy Corp., Ohio Edison Company, The
      Cleveland Electric Illuminating Company, The Toledo Edison Company, Pennsylvania
      Power Company, Jersey Central Power & Light Company, Metropolitan Edison
      Company and Pennsylvania Electric Company. Information contained herein relating
      to any individual registrant is filed by such registrant on its own behalf.
      No
      registrant makes any representation as to information relating to any other
      registrant, except that information relating to any of the FirstEnergy
      subsidiary registrants is also attributed to FirstEnergy Corp.







This Form 10-Q includes forward-looking statements based on information
      currently available to management. Such statements are subject to certain risks
      and uncertainties. These statements typically contain, but are not limited
      to,
      the terms "anticipate," "potential," "expect," "believe," "estimate" and similar
      words. Actual results may differ materially due to the speed and nature of
      increased competition and deregulation in the electric utility industry,
      economic or weather conditions affecting future sales and margins, changes in
      markets for energy services, changing energy and commodity market prices,
      replacement power costs being higher than anticipated or inadequately hedged,
      the continued ability of FirstEnergy Corp.’s regulated utilities to collect
      transition and other charges or to recover increased transmission costs,
      maintenance costs being higher than anticipated, legislative and regulatory
      changes (including revised environmental requirements), and the legal and
      regulatory changes resulting from the implementation of the Energy Policy Act
      of
      2005 (including, but not limited to, the repeal of the Public Utility Holding
      Company Act of 1935), the uncertainty of the timing and amounts of the capital
      expenditures needed to, among other things, implement the Air Quality Compliance
      Plan (including that such amounts could be higher than anticipated) or levels
      of
      emission reductions related to the Consent Decree resolving the New Source
      Review litigation, adverse regulatory or legal decisions and outcomes
      (including, but not limited to, the revocation of necessary licenses or
      operating permits, fines or other enforcement actions and remedies) of
      governmental investigations and oversight, including by the Securities and
      Exchange Commission, the United States Attorney’s Office, the Nuclear Regulatory
      Commission and the various state public utility commissions as disclosed in
      the
      registrants’ Securities and Exchange Commission filings, generally, and with
      respect to the Davis-Besse Nuclear Power Station outage and heightened scrutiny
      at the Perry Nuclear Power Plant in particular, the timing and outcome of
      various proceedings before the Public Utilities Commission of Ohio (including,
      but not
      limited to, the successful resolution of the issues remanded to the
      Public Utilities Commissioni of Ohio by the Ohio Supreme Court
      regarding the Rate Stabilization Plan) and the Pennsylvania Public Utility
      Commission, including the transition rate plan filings for Met-Ed and Penelec,
      the continuing availability and operation of generating units, the ability
      of
      generating units to continue to operate at, or near full capacity, the inability
      to accomplish or realize anticipated benefits from strategic goals (including
      employee workforce initiatives), the anticipated benefits from voluntary pension
      plan contributions, the ability to improve electric commodity margins and to
      experience growth in the distribution business, the ability to access the public
      securities and other capital markets and the cost of such capital, the outcome,
      cost and other effects of present and potential legal and administrative
      proceedings and claims related to the August 14, 2003 regional power
      outages, the successful completion of the share repurchase program announced
      on
      August 10, 2006, the risks and other factors discussed from time to time in
      the registrants’ Securities and Exchange Commission filings, including their
      annual report on Form 10-K for the year ended December 31, 2005, and other
      similar factors. A security rating is not a recommendation to buy, sell or
      hold
      securities and it may be subject to revision or withdrawal at any time by the
      credit rating agency. The registrants expressly disclaim any current intention
      to update any forward-looking statements contained herein as a result of new
      information, future events, or otherwise.














**TABLE
          OF
          CONTENTS**
 
 
 
 **Pages****Glossary
                    of Terms**
                iii-v**Part
                    I.****Financial
                    Information****Items
                    1. and 2. - Financial Statements and Management’s Discussion and Analysis
                    of**
                  **Financial
                    Condition and Results of Operations.**Notes
                    to
                    Consolidated Financial Statements
                1-30**FirstEnergy
                    Corp.**Consolidated
                    Statements of Income
                31Consolidated
                    Statements of Comprehensive Income
                32Consolidated
                    Balance Sheets
                33Consolidated
                    Statements of Cash Flows
                34Report
                    of
                    Independent Registered Public Accounting Firm
                35Management's
                    Discussion and Analysis of Results of Operations and
                36-76Financial
                    Condition**Ohio
                    Edison Company**Consolidated
                    Statements of Income and Comprehensive Income
                77Consolidated
                    Balance Sheets
                78Consolidated
                    Statements of Cash Flows
                79Report
                    of
                    Independent Registered Public Accounting Firm
                80Management's
                    Discussion and Analysis of Results of Operations and
                81-96Financial
                    Condition**The
                    Cleveland Electric Illuminating Company**Consolidated
                    Statements of Income and Comprehensive Income
                97Consolidated
                    Balance Sheets
                98Consolidated
                    Statements of Cash Flows
                99Report
                    of
                    Independent Registered Public Accounting Firm
                100Management's
                    Discussion and Analysis of Results of Operations and
                101-114Financial
                    Condition**The
                    Toledo Edison Company**Consolidated
                    Statements of Income and Comprehensive Income
                115Consolidated
                    Balance Sheets
                116Consolidated
                    Statements of Cash Flows
                117Report
                    of
                    Independent Registered Public Accounting Firm
                118Management's
                    Discussion and Analysis of Results of Operations and
                119-131Financial
                    Condition**Pennsylvania
                    Power Company**ConsolidatedStatements of
                    Income
                132ConsolidatedBalance
                    Sheets
                133ConsolidatedStatements of
                    Cash Flows
                134Report
                    of
                    Independent Registered Public Accounting Firm
                135Management's
                    Discussion and Analysis of Results of Operations and
                136-144Financial
                    Condition
 
   i
  **TABLE
          OF
          CONTENTS (Cont'd)**
 
 
 **Pages****Jersey
                    Central Power & Light Company**Consolidated
                    Statements of Income and Comprehensive Income
                145Consolidated
                    Balance Sheets
                146Consolidated
                    Statements of Cash Flows
                147Report
                    of
                    Independent Registered Public Accounting Firm
                148Management's
                    Discussion and Analysis of Results of Operations and
                149-159Financial
                    Condition**Metropolitan
                    Edison Company**Consolidated
                    Statements of Income and Comprehensive Income
                160Consolidated
                    Balance Sheets
                161Consolidated
                    Statements of Cash Flows
                162Report
                    of
                    Independent Registered Public Accounting Firm
                163Management's
                    Discussion and Analysis of Results of Operations and
                164-174Financial
                    Condition**Pennsylvania
                    Electric Company**Consolidated
                    Statements of Income and Comprehensive Income
                175Consolidated
                    Balance Sheets
                176Consolidated
                    Statements of Cash Flows
                177Report
                    of
                    Independent Registered Public Accounting Firm
                178Management's
                    Discussion and Analysis of Results of Operations and
                179-189Financial
                    Condition**Item
                    3.****Quantitative
                    and Qualitative Disclosures About Market Risk.**
                190**Item
                    4.****Controls
                    and Procedures.**
                190**Part
                    II.****Other
                    Information****Item
                    1.****Legal
                    Proceedings.**
                191**Item
                    1A.****Risk
                    Factors.**
                191**Item
                    2.****Unregistered
                    Sales of Equity Securities and Use of Proceeds.**
                191**Item
                    6.****Exhibits.**
                192-193
 
 ii
  
 **GLOSSARY
        OF
        TERMS**




The
      following
      abbreviations and acronyms are used in this report to identify FirstEnergy
      Corp.
      and its current and former


subsidiaries:


ATSI
                American
                    Transmission Systems, Inc., owns and operates transmission
                    facilitiesCEI
                The
                    Cleveland
                    Electric Illuminating Company, an Ohio electric utility operating
                    subsidiaryCenterior
                Centerior
                    Energy Corporation, former parent of CEI and TE, which merged
                    with OE to
                    form
                  FirstEnergy
                    on
                    November 8, 1997CFC
                Centerior
                    Funding Corporation, a wholly owned finance subsidiary of
                    CEICompanies
                OE,
                    CEI, TE,
                    Penn, JCP&L, Met-Ed and PenelecFENOC
                FirstEnergy
                    Nuclear Operating Company, operates nuclear generating
                    facilitiesFES
                FirstEnergy
                    Solutions Corp., provides energy-related products and
                    servicesFESC
                FirstEnergy
                    Service Company, provides legal, financial, and other corporate
                    support
                    servicesFGCO
                FirstEnergy
                    Generation Corp., owns and operates non-nuclear generating
                    facilitiesFirstCom
                First
                    Communications, LLC, provides local and long-distance telephone
                    serviceFirstEnergy
                FirstEnergy
                    Corp., a public utility holding companyFSG
                FirstEnergy
                    Facilities Services Group, LLC, the parent company of several
                    heating,
                    ventilation,
                  air
                    conditioning and energy management companiesGPU
                GPU,
                    Inc.,
                    former parent of JCP&L, Met-Ed and Penelec, which merged with
                    FirstEnergy on
                  November 7,
                    2001JCP&L
                Jersey
                    Central
                    Power & Light Company, a New Jersey electric utility operating
                    subsidiaryJCP&L
                    Transition Funding
                JCP&L
                    Transition Funding LLC, a Delaware limited liability company
                    and issuer of
                    transition bondsJCP&L
                    Transition Funding II
                JCP&L
                    Transition Funding II LLC, a Delaware limited liability company
                    and issuer
                    of transition bondsMet-Ed
                Metropolitan
                    Edison Company, a Pennsylvania electric utility operating
                    subsidiaryMYR
                MYR
                    Group,
                    Inc., a utility infrastructure construction service
                    companyNGC
                FirstEnergy
                    Nuclear Generation Corp., owns nuclear generating
                    facilitiesOE
                Ohio
                    Edison
                    Company, an Ohio electric utility operating subsidiaryOE
                    Companies
                OE
                    and
                    PennOhio
                    Companies
                CEI,
                    OE and
                    TEPenelec
                Pennsylvania
                    Electric Company, a Pennsylvania electric utility operating
                    subsidiaryPenn
                Pennsylvania
                    Power Company, a Pennsylvania electric utility operating subsidiary
                    of
                    OEPNBV
                PNBV
                    Capital
                    Trust, a special purpose entity created by OE in 1996Shippingport
                Shippingport
                    Capital Trust, a special purpose entity created by CEI and TE
                    in
                    1997TE
                The
                    Toledo
                    Edison Company, an Ohio electric utility operating
                    subsidiaryTEBSA
                Termobarranquilla
                    S.A., Empresa de Servicios PublicosThe
                    following
                    abbreviations and acronyms are used to identify frequently used
                    terms in
                    this report:ALJ
                Administrative
                    Law JudgeAOCL
                Accumulated
                    Other Comprehensive LossAPB
                Accounting
                    Principles BoardAPB
                    25
                APB
                    Opinion
                    No. 25, "Accounting for Stock Issued to Employees"APB
                    29
                APB
                    Opinion
                    No. 29, "Accounting for Nonmonetary Transactions"ARB
                Accounting
                    Research BulletinARB
                    43
                ARB
                    No. 43,
                    "Restatement and Revision of Accounting Research
                    Bulletins"ARO
                Asset
                    Retirement ObligationB&W
                Babcock
&
                    Wilcox CompanyBechtel
                Bechtel
                    Power
                    CorporationBGS
                Basic
                    Generation ServiceBTU
                British
                    Thermal UnitCAIDI
                Customer
                    Average Interruption Duration IndexCAIR
                Clean
                    Air
                    Interstate RuleCAL
                Confirmatory
                    Action LetterCAMR
                Clean
                    Air
                    Mercury RuleCBP
                Competitive
                    Bid ProcessCIEP
                Commercial
                    Industrial Energy PriceCO2
                Carbon
                    DioxideCTC
                Competitive
                    Transition ChargeDCPD
                Deferred
                    Compensation Plan for Outside DirectorsDIG
                    C20
                Derivatives
                    Implementation Group Issue No. C20, “Scope Exceptions: Interpretations of
                    the
                  Meaning
                    of Not
                    Clearly and Closely Related in Paragraph 10(b) regarding Contracts
                    with a
                  Price
                    Adjustment Feature”
  
 iii
  
 **GLOSSARY
        OF
        TERMS Cont’d.**




DOJ
                U.S.
                    Department of JusticeDRA
                Division
                    of
                    the Ratepayer AdvocateECAR
                East
                    Central
                    Area Reliability Coordination AgreementEDCP
                Executive
                    Deferred Compensation PlanEITF
                Emerging
                    Issues Task ForceEPA
                U.S.
                    Environmental Protection AgencyEPACT
                Energy
                    Policy
                    Act of 2005ERO
                Electric
                    Reliability OrganizationESOP
                Employee
                    Stock
                    Ownership PlanFASB
                Financial
                    Accounting Standards BoardFERC
                U.S.
                    Federal
                    Energy Regulatory CommissionFIN
                FASB
                    InterpretationFIN
                    46(R)
                FIN
                    46
                    (revised December 2003), "Consolidation of Variable Interest
                    Entities"FIN
                    46(R)-6
                FIN
                    46(R)-6,
                    “Determining the Variability to be Considered in Applying FASB
                    interpretation No. 46(R)”FIN
                    47
                FIN
                    47,
                    "Accounting for Conditional Asset Retirement Obligations - an
                    interpretation of FASB
                  Statement
                    No.
                    143"FIN
                    48
                FIN
                    48,
                    “Accounting for Uncertainty in Income Taxes - an interpretation
                    of FASB
                    Statement No.109”FMB
                First
                    Mortgage
                    BondsFSP
                FASB
                    Staff
                    PositionFSP
                    FIN
                    13-2
                FSP
                    FIN 13-2,
                    “Accounting for a Change or Projected Change in the Timing of
                    Cash Flows
                    Relating
                  to
                    Income
                    Taxes Generated by a Leveraged Lease Transaction”GAAP
                Accounting
                    Principles Generally Accepted in the United StatesGCAF
                Generation
                    Charge Adjustment FactorGHG
                Greenhouse
                    GasesKWH
                Kilowatt-hoursLOC
                Letter
                    of
                    CreditLTIP
                Long-Term
                    Incentive ProgramMEIUG
                Met-Ed
                    Industrial Users GroupMISO
                Midwest
                    Independent Transmission System Operator, Inc.Moody’s
                Moody’s
                    Investors ServiceMOU
                Memorandum
                    of
                    UnderstandingMSG
                Market
                  Support GenerationMTC
                Market
                    Transition ChargeMW
                MegawattsMWH
                Megawatt-hoursNAAQS
                National
                    Ambient Air Quality StandardsNERC
                North
                    American
                    Electric Reliability CouncilNJBPU
                New
                    Jersey
                    Board of Public UtilitiesNOAC
                Northwest
                    Ohio
                    Aggregation CoalitionNOPR
                Notice
                    of
                    Proposed RulemakingNOV
                Notices
                    of
                    ViolationNOX
                Nitrogen
                    OxideNRC
                U.S.
                    Nuclear
                    Regulatory CommissionNUG
                Non-Utility
                    GenerationNUGC
                Non-Utility
                    Generation ChargeOCA
                Office
                    of
                    Consumer AdvocateOCC
                Office
                    of the
                    Ohio Consumers' CounselOCI
                Other
                    Comprehensive IncomeOPEB
                Other
                    Post-Employment BenefitsOSBA
                Office
                    of
                    Small Business AdvocateOTS
                Office
                    of
                    Trial StaffPaDEP
                Pennsylvania
                    Department of Environmental ProtectionPCAOB
                Public
                    Company
                    Accounting Oversight BoardPICA
                Penelec
                    Industrial Customer AssociationPJM
                PJM
                    Interconnection L. L. C.PLR
                Provider
                    of
                    Last ResortPPUC
                Pennsylvania
                    Public Utility CommissionPRP
                Potentially
                    Responsible PartyPUCO
                Public
                    Utilities Commission of OhioPUHCA
                Public
                    Utility
                    Holding Company Act of 1935RCP
                Rate
                    Certainty
                    PlanRFP
                Request
                    for
                    ProposalRSP
                Rate
                    Stabilization Plan
 
 iv
 
 **GLOSSARY
        OF
        TERMS Cont’d.**




RTC
              Regulatory
                Transition ChargeRTO
              Regional
                  Transmission OrganizationRTOR
              Regional
                  Through and Out RatesS&P
              Standard
&
                  Poor’s Ratings ServiceSAB
                  108
              SEC
                  Staff
                  Accounting Bulletin No. 108, “Considering the Effects of Prior Year
                  Misstatements when
                Quantifying
                  Misstatements in Current Year Financial Statements”SAIFI
              System
                  Average
                  Interruption Frequency IndexSBC
              Societal
                  Benefits ChargeSEC
              U.S.
                  Securities and Exchange CommissionSECA
              Seams
                  Elimination Cost AdjustmentSFAS
              Statement
                  of
                  Financial Accounting StandardsSFAS
                  123
              SFAS
                  No. 123,
                  "Accounting for Stock-Based Compensation"SFAS
                  123(R)
              SFAS
                  No.
                  123(R), "Share-Based Payment"SFAS
                  133
              SFAS
                  No. 133,
                  “Accounting for Derivative Instruments and Hedging
                  Activities”SFAS
                  142
              SFAS
                  No. 142,
                  “Goodwill and Other Intangible Assets”SFAS
                  143
              SFAS
                  No. 143,
                  "Accounting for Asset Retirement Obligations"SFAS
                  144
              SFAS
                  No. 144,
                  "Accounting for the Impairment or Disposal of Long-Lived
                  Assets"SFAS
                  157
              SFAS
                  No. 157,
                  “Fair Value Measurements”SFAS
                  158
              SFAS
                  No. 158,
                  “Employers’ Accounting for Defined Benefit Pension and Other
                  Postretirement
                Plans-an
                  amendment of FASB Statements No. 87, 88, 106, and
                  132(R)”SIP
              State
                Implementation Plan(s) Under the Clean Air ActSO2
              Sulfur
                  DioxideSRM
              Special
                  Reliability MasterTBC
              Transition
                  Bond ChargeTMI-2
              Three
                  Mile
                  Island Unit 2VIE
              Variable
                  Interest EntityVMEP
              Vegetation
                  Management Enhancement Project


v





**PART
        I.
        FINANCIAL INFORMATION**
 
 **FIRSTENERGY
        CORP. AND SUBSIDIARIES**
 **OHIO
        EDISON
        COMPANY AND SUBSIDIARIES**
 **THE
        CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES**
 **THE
        TOLEDO
        EDISON COMPANY AND SUBSIDIARY**
 **PENNSYLVANIA
        POWER COMPANY AND SUBSIDIARY**
 **JERSEY
        CENTRAL POWER & LIGHT COMPANY AND SUBSIDIARIES**
 **METROPOLITAN
        EDISON COMPANY AND SUBSIDIARIES**
 **PENNSYLVANIA
        ELECTRIC COMPANY AND SUBSIDIARIES**
 
 **NOTES
        TO
        CONSOLIDATED FINANCIAL STATEMENTS**
 **(UNAUDITED)**
 
 
 **1.
        -
        ORGANIZATION AND BASIS OF PRESENTATION**
 
 FirstEnergy’s
        principal business is the holding, directly or indirectly, of all of the
        outstanding common stock of its eight principal electric utility operating
        subsidiaries: OE, CEI, TE, Penn, ATSI, JCP&L, Met-Ed and Penelec. Penn is a
        wholly owned subsidiary of OE. FirstEnergy's consolidated financial statements
        also include its other principal subsidiaries: FENOC, FES and its subsidiary
        FGCO, NGC, FESC and FSG.
 
 FirstEnergy
        and its
        subsidiaries follow GAAP and comply with the regulations, orders, policies
        and
        practices prescribed by the SEC, FERC and, as applicable, PUCO, PPUC and
        NJBPU.
        The preparation of financial statements in conformity with GAAP requires
        management to make periodic estimates and assumptions that affect the reported
        amounts of assets, liabilities, revenues and expenses and disclosure of
        contingent assets and liabilities. Actual results could differ from these
        estimates. The reported results of operations are not indicative of results
        of
        operations for any future period.
 
 These
        statements
        should be read in conjunction with the financial statements and notes included
        in the combined Annual Report on Form 10-K for the year ended December 31,
        2005 for FirstEnergy and the Companies. The consolidated unaudited financial
        statements of FirstEnergy and each of the Companies reflect all normal recurring
        adjustments that, in the opinion of management, are necessary to fairly present
        results of operations for the interim periods. Certain businesses divested
        in
        the nine months ended September 30, 2005 have been classified as
        discontinued operations on the Consolidated Statements of Income (see Note
        4).
        As discussed in Note 13, interim period segment reporting in 2005 was
        reclassified to conform with the current year business segment organizations
        and
        operations.
 
 FirstEnergy
        and its
        subsidiaries consolidate all majority-owned subsidiaries over which they
        exercise control and, when applicable, entities for which they have a
        controlling financial interest. Intercompany transactions and balances are
        eliminated in consolidation. FirstEnergy consolidates a VIE (see Note 9)
        when it
        is determined to be the VIE's primary beneficiary. Investments in
        nonconsolidated affiliates over which FirstEnergy and its subsidiaries have
        the
        ability to exercise significant influence, but not control, (20-50 percent
        owned
        companies, joint ventures and partnerships) are accounted for under the equity
        method. Under the equity method, the interest in the entity is reported as
        an
        investment in the Consolidated Balance Sheet and the percentage share of
        the
        entity’s earnings is reported in the Consolidated Statement of Income. Certain
        prior year amounts have been reclassified to conform to the current
        presentation.
 
 FirstEnergy's
        and
        the Companies' independent registered public accounting firm has performed
        reviews of, and issued reports on, these consolidated interim financial
        statements in accordance with standards established by the PCAOB. Pursuant
        to
        Rule 436(c) under the Securities Act of 1933, their reports of those reviews
        should not be considered a report within the meaning of Section 7 and 11
        of that
        Act, and the independent registered public accounting firm’s liability under
        Section 11 does not extend to them.
 
  1
  **2.
        -
        EARNINGS PER SHARE**
 
 Basic
        earnings per
        share are computed using the weighted average of actual common shares
        outstanding during the respective period as the denominator. The denominator
        for
        diluted earnings per share reflects the weighted average of common shares
        outstanding plus the potential additional common shares that could result
        if
        dilutive securities and other agreements to issue common stock were exercised. On
        August 10, 2006, FirstEnergy repurchased 10.6 million shares,
        approximately 3.2%, of its outstanding common stock through an accelerated
        share
        repurchase program (see Note 10(D)). The initial purchase price was
        $600 million, or $56.44 per share. The final purchase price will be
        adjusted to reflect the ultimate cost to acquire the shares over a period
        of up
        to seven months. The
        2006 basic and
        diluted earnings per share results reflect the impact associated with the
        August
        2006 accelerated share repurchase program. FirstEnergy intends to settle,
        in
        shares or cash, any obligation on its part to pay the difference between
        the
        average of the daily volume-weighted average price of the shares as calculated
        under the program and the initial price of the shares. Since the effect of
        any
        potential settlement in shares is currently unknown and therefore not expected
        to be dilutive, there is no impact on reported diluted earnings per share.
        The
        following table reconciles the computation of basic and diluted earnings
        per
        share of common stock before discontinued operations:
 
 **Three
                  Months Ended**
              
              **Nine
                  Months Ended****September
                  30,**
              
              **September
                  30,****Reconciliation
                  of Basic and Diluted Earnings per Share**
              
              **2006**
              
              **2005**
              
              **2006**
              
              **2005*****(In
                  millions, except per share amounts)***Income
                  Before
                  Discontinued Operations
              
              $
              454
              
              $
              332
              
              $
              979
              
              $
              652Less:
                  Redemption premium on subsidiary preferred stock
              
              
              -
              
              
              -
              
              
              (3
              )
              
              -Earnings
                  on
                  Common Stock Before Discontinued Operations
              
              $
              454
              
              $
              332
              
              $
              976
              
              $
              652Weighted
                  Average Shares of Common Stock Outstanding:Denominator
                  for basic earnings per share
              
              
              322
              
              
              328
              
              
              326
              
              
              328Assumed
                  exercise of dilutive stock options and awards
              
              
              3
              
              
              2
              
              
              3
              
              
              2Denominator
                  for diluted earnings per share
              
              
              325
              
              
              330
              
              
              329
              
              
              330Earnings
                  Before Discontinued Operations per Common Share:Basic
              
              
              $1.41
              
              
              $1.01
              
              
              $2.99
              
              
              $1.99Diluted
              
              
              $1.40
              
              
              $1.01
              
              
              $2.97
              
              
              $1.98
 
 **3.
        -
        GOODWILL**
 
 In
        a business
        combination, the excess of the purchase price over the estimated fair values
        of
        assets acquired and liabilities assumed is recognized as goodwill. Based
        on the
        guidance provided by SFAS 142, FirstEnergy evaluates its goodwill for impairment
        at least annually and more frequently as indicators of impairment arise.
        In
        accordance with the accounting standard, if the fair value of a reporting
        unit
        is less than its carrying value (including goodwill), the goodwill is tested
        for
        impairment. If impairment is indicated, FirstEnergy recognizes a loss -
        calculated as the difference between the implied fair value of a reporting
        unit's goodwill and the carrying value of the goodwill.
 
 FirstEnergy's
        2006
        annual review was completed in the third quarter of 2006 with no impairment
        indicated. As discussed in Note 11 to the consolidated financial statements,
        Met-Ed and Penelec have rate increase requests pending before the PPUC. The
        annual goodwill impairment analysis assumed management's best estimate of
        the
        rate increases that are expected to be granted in January 2007. If the PPUC
        authorizes less than the amounts assumed, an additional impairment analysis
        would be performed at that time and this could result in a future goodwill
        impairment loss that could be material. If rate relief were completely denied,
        it is estimated that approximately $604 million of Met-Ed’s goodwill would
        be impaired and approximately $374 million of Penelec’s goodwill would be
        impaired, and those amounts would be written off by those companies. However,
        no
        adjustment to FirstEnergy’s goodwill on a consolidated basis would be recognized
        in that circumstance because the fair value of its regulated segment (which
        represents FirstEnergy's reporting unit to evaluate goodwill) would continue
        to
        exceed the carrying value of its investment in the segment.
 
 FirstEnergy's
        goodwill primarily relates to its regulated services segment. In the nine
        months
        ended September 30, 2006, FirstEnergy adjusted goodwill related to the
        divestiture of a non-core asset (62% interest in MYR), a successful tax claim
        relating to the former Centerior companies, and adjustments to the former
        GPU
        companies due to the realization of tax benefits that had been reserved in
        purchase accounting. The following tables reconcile changes to goodwill
        for the three months and nine months ended September 30,
        2006.
  2
  
 **Three
                  Months Ended**
              
              **FirstEnergy**
              
              **CEI**
              
              **TE**
              
              **JCP&L**
              
              **Met-Ed**
              
              **Penelec*****(In
                  millions)***Balance
                  as of
                  July 1, 2006
              
              $
              5,940
              
              $
              1,688
              
              $
              501
              
              $
              1,978
              
              $
              860
              
              $
              878Adjustments
                  related to GPU acquisition
              
              
              (5
              )
              
              
              
              
              
              
              
              (1
              )
              
              
              
              
              (4
              )Balance
                  as of
                  September 30, 2006
              
              $
              5,935
              
              $
              1,688
              
              $
              501
              
              $
              1,977
              
              $
              860
              
              $
              874
 
 **Nine
                  Months Ended**
              
              **FirstEnergy**
              
              **CEI**
              
              **TE**
              
              **JCP&L**
              
              **Met-Ed**
              
              **Penelec*****(In
                  millions)***Balance
                  as of
                  January 1, 2006
              
              $
              6,010
              
              $
              1,689
              
              $
              501
              
              $
              1,986
              
              $
              864
              
              $
              882Non-core
                  assets sale
              
              
              (53
              )Adjustments
                  related to Centerior acquisition
              
              
              (1
              )
              
              (1
              )Adjustments
                  related to GPU acquisition
              
              
              (21
              )
              
              
              
              
              
              
              
              (9
              )
              
              (4
              )
              
              (8
              )Balance
                  as of
                  September 30, 2006
              
              $
              5,935
              
              $
              1,688
              
              $
              501
              
              $
              1,977
              
              $
              860
              
              $
              874
 
 
 **4.
        -
        DIVESTITURES AND DISCONTINUED OPERATIONS**
 
 In
        August 2006,
        FirstEnergy sold two FSG subsidiaries (Roth Bros. and Hattenbach) for a net
        after-tax gain of $1.9 million. The remaining FSG subsidiaries continue to
        be actively marketed and qualify as assets held for sale in accordance with
        SFAS 144 because FirstEnergy anticipates that the transfer of these assets,
        with a net carrying value of $30.6 million as of September 30, 2006,
        will qualify for recognition as completed sales within one year. As of
        September 30, 2006, the remaining FSG subsidiaries classified as held for
        sale did not meet the criteria for discontinued operations. The carrying
        amounts
        of FSG's assets and liabilities are not material and have not been presented
        separately as assets held for sale on FirstEnergy's Consolidated Balance
        Sheets.
        See Note 13 for FSG's segment financial information.
  In March 2006, FirstEnergy sold 60% of its interest in MYR for an after-tax
        gain
        of $0.2 million. In June 2006, FirstEnergy sold an additional 1.67% interest.
        As
        a result of the March sale, FirstEnergy deconsolidated MYR in the first quarter
        of 2006 and accounts for its remaining 38.33% interest under the equity
        method.
  In March 2005, FirstEnergy sold 51% of its interest in FirstCom for an after-tax
        gain of $4 million. FirstEnergy accounts for its remaining 31.85% interest
        in FirstCom under the equity method.
 During the first nine months of 2005, FirstEnergy sold three FSG subsidiaries
        (Cranston, Elliott-Lewis and Spectrum), an MYR subsidiary (Power Piping)
        and
        FES' retail natural gas business, resulting in aggregate after-tax gains
        of
        $17 million.
 
 Net
        results
        (including the gains on sales of assets discussed above) for Cranston,
        Elliott-Lewis, Power Piping and FES' retail natural gas business of
        $18 million for the nine months ended September 30, 2005 are reported
        as discontinued operations on FirstEnergy's Consolidated Statements of Income.
        Pre-tax operating results for these entities were $2 million for the nine
        months ended September 30, 2005. Revenues associated with discontinued
        operations for the nine months ended September 30, 2005 were
        $207 million. The following table summarizes the sources of income from
        discontinued operations (in millions) for the nine months ended
        September 30, 2005:
 
 Discontinued
                  Operations (Net of tax)Gain
                  on
                  sale:Natural
                  gas
                  business
              
              $
              5FSG
                  and MYR
                  subsidiaries
              
              
              12Reclassification
                  of operating income
              
              
              1Total
              
              $
              18
 
 **5.
        -
        DERIVATIVE INSTRUMENTS**
  FirstEnergy is exposed to financial risks resulting from the fluctuation
        of
        interest rates and commodity prices, including prices for electricity, natural
        gas, coal and energy transmission. To manage the volatility relating to these
        exposures, FirstEnergy uses a variety of non-derivative and derivative
        instruments, including forward contracts, options, futures contracts and
        swaps.
        The derivatives are used principally for hedging purposes. FirstEnergy’s Risk
        Policy Committee, comprised of members of senior management, provides general
        management oversight to risk management activities. The Committee is responsible
        for promoting the effective design and implementation of sound risk management
        programs and oversees compliance with corporate risk management policies
        and
        established risk management practices.
  3
  FirstEnergy accounts for derivative instruments on its Consolidated Balance
        Sheet at their fair value unless they meet the normal purchase and normal
        sales
        exception criterion. Derivatives that meet that criterion are accounted for
        on
        the accrual basis. The changes in the fair value of derivative instruments
        that
        do not meet the normal purchase and sales criterion are recorded in current
        earnings, in AOCL, or as part of the value of the hedged item, depending
        on
        whether or not it is designated as part of a hedge transaction, the nature
        of
        the hedge transaction and hedge effectiveness.
  FirstEnergy hedges anticipated transactions using cash flow hedges. Such
        transactions include hedges of anticipated electricity and natural gas purchases
        and anticipated interest payments associated with future debt issues. The
        effective portion of such hedges are initially recorded in equity as other
        comprehensive income or loss and are subsequently included in net income
        as the
        underlying hedged commodities are delivered or interest payments are made.
        Gains
        and losses from any ineffective portion of cash flow hedges are included
        directly in earnings.
  The net deferred losses of $48 million included in AOCL as of September 30,
        2006, for derivative hedging activity, as compared to the December 31, 2005
        balance of $78 million of net deferred losses, resulted from a net
        $13 million decrease related to current hedging activity and a
        $17 million decrease due to net hedge losses reclassified into earnings
        during the nine months ended September 30, 2006. Based on current estimates,
        approximately $15 million (after tax) of the net deferred losses on
        derivative instruments in AOCL as of September 30, 2006 is expected to be
        reclassified to earnings during the next twelve months as hedged transactions
        occur. The fair value of these derivative instruments fluctuate from period
        to
        period based on various market factors.
  FirstEnergy has entered into swaps that have been designated as fair value
        hedges of fixed-rate, long-term debt issues to protect against the risk of
        changes in the fair value of fixed-rate debt instruments due to lower interest
        rates. Swap maturities, call options, fixed interest rates received, and
        interest payment dates match those of the underlying debt obligations. During
        the nine months ended September 30, 2006, FirstEnergy unwound swaps with
        a total
        notional amount of $350 million for which it paid $1 million in cash.
        The losses will be recognized in earnings over the remaining maturity of
        each
        respective hedged security as increased interest expense. As of
        September 30, 2006, FirstEnergy had interest rate swaps with an aggregate
        notional value of $750 million and a fair value of
        ($29) million.
  During 2005 and the first nine months of 2006, FirstEnergy entered into several
        forward starting swap agreements (forward swaps) in order to hedge a portion
        of
        the consolidated interest rate risk associated with the anticipated issuances
        of
        fixed-rate, long-term debt securities for one or more of its subsidiaries
        during
        2006 - 2008 as outstanding debt matures. These derivatives are treated as
        cash
        flow hedges, protecting against the risk of changes in future interest payments
        resulting from changes in benchmark U.S. Treasury rates between the date
        of
        hedge inception and the date of the debt issuance. FirstEnergy revised the
        tenor
        and timing of its financing plan during the first nine months of 2006.
        FirstEnergy terminated and revised forward swaps with an aggregate notional
        value of $600 million during the second quarter of 2006, ultimately
        terminating the swaps as its subsidiaries issued long-term debt. In the third
        quarter of 2006, FirstEnergy revised the timing of swaps with an aggregate
        notional value of $100 million. As required by SFAS 133, FirstEnergy
        assessed the amount of ineffectiveness of the hedges at each termination.
        FirstEnergy received cash gains of $43 million, of which approximately
        $6 million ($4 million net of tax) was deemed ineffective and
        recognized in earnings in the first nine months of 2006. The remaining gain
        deemed effective in the amount of approximately $38 million
        ($23 million net of tax) was recorded in other comprehensive income and
        will subsequently be recognized in earnings over the terms of the associated
        future debt. As of September 30, 2006, FirstEnergy had forward swaps with
        an
        aggregate notional amount of $725 million and a long-term debt securities
        fair value of ($2) million.
 
 **6.
        - STOCK
        BASED COMPENSATION**
  Effective January 1, 2006, FirstEnergy adopted SFAS 123(R), which requires
        the
        expensing of stock-based compensation. Under SFAS 123(R), all share-based
        compensation cost is measured at the grant date based on the fair value of
        the
        award, and is recognized as an expense over the employee’s requisite service
        period. FirstEnergy adopted the modified prospective method, under which
        compensation expense recognized in the three months and nine months ended
        September 30, 2006 included the expense for all share-based payments
        granted prior to but not yet vested as of January 1, 2006. Results for
        prior periods were not restated.
  Prior to the adoption of SFAS 123(R) on January, 1, 2006, FirstEnergy’s LTIP,
        EDCP, ESOP, and DCPD stock-based compensation programs were accounted for
        under
        the recognition and measurement principles of APB 25 and related
        interpretations. The LTIP includes four stock-based compensation programs
        -
        restricted stock, restricted stock units, stock options and performance shares.
  4
  Under APB 25, no compensation expense was reflected in net income for stock
        options as all options granted under those plans have exercise prices equal
        to
        the market value of the underlying common stock on the respective grant dates,
        resulting in substantially no intrinsic value. The pro forma effects on net
        income for stock options were instead disclosed in a footnote to the financial
        statements. Under APB 25 and SFAS 123(R), compensation expense was recorded
        in
        the income statement for restricted stock, restricted stock units, performance
        shares and the EDCP and DCPD programs. No stock options have been granted
        since
        the third quarter of 2004. Consequently, the impact of adopting SFAS 123(R)
        was
        not material to FirstEnergy's net income and earnings per share in the three
        months and nine months ended September 30, 2006. In the year of adoption,
        all disclosures prescribed by SFAS 123(R) are required to be included in
        both
        the quarterly Form 10-Q filings as well as the annual Form 10-K filing. However,
        due to the immaterial impact of the adoption of SFAS 123(R) on FirstEnergy's
        financial results, only condensed disclosure has been provided. Reference
        is
        made to FirstEnergy’s annual report on Form 10-K for the year ended December 31,
        2005 for expanded annual disclosure.
  The following table illustrates the effect on net income and earnings per
        share
        for the three months and nine months ended September 30, 2005, as if
        FirstEnergy had adopted SFAS 123(R) as of January 1, 2005:
 
 **Three
                  Months**
              
              **Nine
                  Months****(In
                  millions, except per share amounts)**Net
                  Income, as
                  reported
              
              $
              332
              
              $
              670Add
                  back
                  compensation expensereported
                  in
                  net income, net of tax (based onAPB
                  25)*
              
              
              17
              
              
              40Deduct
                  compensation expense basedupon
                  estimated
                  fair value, net of tax*
              
              
              (19
              )
              
              (47
              )Pro
                  forma net
                  income
              
              $
              330
              
              $
              663Earnings
                  Per
                  Share of Common Stock -BasicAs
                  Reported
              
              
              $1.01
              
              
              $2.04Pro
                  Forma
              
              
              $1.01
              
              
              $2.02DilutedAs
                  Reported
              
              
              $1.01
              
              
              $2.03Pro
                  Forma
              
              
              $1.00
              
              
              $2.01
 
 *  Includes
        restricted
        stock, restricted stock units, stock options, performance
 shares,
        ESOP, EDCP
        and DCPD.
 
 **7.
        - ASSET
        RETIREMENT OBLIGATIONS**
 
 FirstEnergy
        has
        recognized applicable legal obligations under SFAS 143 for nuclear power
        plant
        decommissioning, reclamation of a sludge disposal pond and closure of two
        coal
        ash disposal sites. In addition, FirstEnergy has recognized conditional
        retirement obligations (primarily for asbestos remediation) in accordance
        with
        FIN 47, which was implemented on December 31, 2005. Had FIN 47 been
        applied in the nine months ended September 30, 2005, the impact on earnings
        would have been immaterial.
 
 The
        ARO liability of
        $1.2 billion as of September 30, 2006 primarily relates to the nuclear
        decommissioning of the Beaver Valley, Davis-Besse, Perry and TMI-2 nuclear
        generating facilities. The obligation to decommission these units was developed
        based on site specific studies performed by an independent engineer. FirstEnergy
        uses an expected cash flow approach to measure the fair value of the nuclear
        decommissioning ARO.
  FirstEnergy maintains nuclear decommissioning trust funds that are legally
        restricted for purposes of settling the nuclear decommissioning ARO. As of
        September 30, 2006, the fair value of the decommissioning trust assets was
        $1.9 billion.
 
 
  5
  
 
 The
        following tables
        analyze changes to the ARO balances during the three months and nine months
        ended September 30, 2006 and 2005, respectively.
 
 **Three
                  Months Ended**
              
              **FirstEnergy**
              
              **OE**
              
              **CEI**
              
              **TE**
              
              **Penn**
              
              **JCP&L**
              
              **Met-Ed**
              
              **Penelec*****(In
                  millions)*****ARO
                  Reconciliation**Balance,
                  July
                  1, 2006
              
              $
              1,160
              
              $
              85
              
              $
              2
              
              $
              26
              
              $
              -
              
              $
              82
              
              $
              146
              
              $
              74Liabilities
                  incurred
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Liabilities
                  settled
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Accretion
              
              
              19
              
              
              2
              
              
              -
              
              
              -
              
              
              -
              
              
              1
              
              
              3
              
              
              2Revisions
                  in
                  estimatedcashflows
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Balance,
                  September 30, 2006
              
              $
              1,179
              
              $
              87
              
              $
              2
              
              $
              26
              
              $
              -
              
              $
              83
              
              $
              149
              
              $
              76Balance,
                  July
                  1, 2005
              
              $
              1,113
              
              $
              208
              
              $
              281
              
              $
              201
              
              $
              143
              
              $
              75
              
              $
              137
              
              $
              68Liabilities
                  incurred
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Liabilities
                  settled
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Accretion
              
              
              18
              
              
              3
              
              
              5
              
              
              4
              
              
              2
              
              
              1
              
              
              2
              
              
              1Revisions
                  in
                  estimatedcashflows
              
              
              (1
              )
              
              (2
              )
              
              (5
              )
              
              (5
              )
              
              11
              
              
              -
              
              
              -
              
              
              -Balance,
                  September 30, 2005
              
              $
              1,130
              
              $
              209
              
              $
              281
              
              $
              200
              
              $
              156
              
              $
              76
              
              $
              139
              
              $
              69
 
 
 **Nine
                  Months Ended**
              
              **FirstEnergy**
              
              **OE**
              
              **CEI**
              
              **TE**
              
              **Penn**
              
              **JCP&L**
              
              **Met-Ed**
              
              **Penelec*****(In
                  millions)*****ARO
                  Reconciliation**Balance,
                  January 1, 2006
              
              $
              1,126
              
              $
              83
              
              $
              8
              
              $
              25
              
              $
              -
              
              $
              80
              
              $
              142
              
              $
              72Liabilities
                  incurred
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Liabilities
                  settled
              
              
              (6
              )
              
              -
              
              
              (6
              )
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Accretion
              
              
              55
              
              
              4
              
              
              -
              
              
              1
              
              
              -
              
              
              3
              
              
              7
              
              
              4Revisions
                  in
                  estimatedcashflows
              
              
              4
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Balance,
                  September 30, 2006
              
              $
              1,179
              
              $
              87
              
              $
              2
              
              $
              26
              
              $
              -
              
              $
              83
              
              $
              149
              
              $
              76Balance,
                  January 1, 2005
              
              $
              1,078
              
              $
              201
              
              $
              272
              
              $
              195
              
              $
              138
              
              $
              72
              
              $
              133
              
              $
              67Liabilities
                  incurred
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Liabilities
                  settled
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Accretion
              
              
              53
              
              
              10
              
              
              14
              
              
              10
              
              
              7
              
              
              4
              
              
              6
              
              
              2Revisions
                  in
                  estimatedcashflows
              
              
              (1
              )
              
              (2
              )
              
              (5
              )
              
              (5
              )
              
              11
              
              
              -
              
              
              -
              
              
              -Balance,
                  September 30, 2005
              
              $
              1,130
              
              $
              209
              
              $
              281
              
              $
              200
              
              $
              156
              
              $
              76
              
              $
              139
              
              $
              69
 
 **8.
        - PENSION
        AND OTHER POSTRETIREMENT BENEFITS**
  FirstEnergy provides noncontributory defined benefit pension plans that cover
        substantially all of its employees. The trusteed plans provide defined benefits
        based on years of service and compensation levels. FirstEnergy also provides
        a
        minimum amount of noncontributory life insurance to retired employees in
        addition to optional contributory insurance. Health care benefits, which
        include
        certain employee contributions, deductibles and co-payments, are available
        upon
        retirement to employees hired prior to January 1, 2005, their dependents
        and, under certain circumstances, their survivors. FirstEnergy recognizes
        the
        expected cost of providing pension benefits and other postretirement benefits
        from the time employees are hired until they become eligible to receive those
        benefits.
  6
  
 The
        components of
        FirstEnergy's net periodic pension and other postretirement benefit costs
        (including amounts capitalized) for the three months and nine months ended
        September 30, 2006 and 2005 consisted of the following:
 
 **Three
                  Months Ended**
              **Nine
                  Months Ended****September
                  30,**
              
              **September
                  30,****Pension
                  Benefits**
              
              **2006**
              
              **2005**
              
              **2006**
              
              **2005*****(In
                  millions)***Service
                  cost
              
              $
              21
              
              $
              19
              
              $
              63
              
              $
              58Interest
                  cost
              
              
              66
              
              
              64
              
              
              199
              
              
              191Expected
                  return on plan assets
              
              
              (99
              )
              
              (86
              )
              
              (297
              )
              
              (259
              )Amortization
                  of prior service cost
              
              
              2
              
              
              2
              
              
              7
              
              
              6Recognized
                  net
                  actuarial loss
              
              
              15
              
              
              9
              
              
              44
              
              
              27Net
                  periodic
                  cost
              
              $
              5
              
              $
              8
              
              $
              16
              
              $
              23
 
 **Three
                  Months Ended**
              **Nine
                  Months Ended****September
                  30,**
              
              **September
                  30,****Other
                  Postretirement Benefits**
              
              **2006**
              
              **2005**
              
              **2006**
              
              **2005*****(In
                  millions)***Service
                  cost
              
              $
              9
              
              $
              10
              
              $
              26
              
              $
              30Interest
                  cost
              
              
              26
              
              
              27
              
              
              79
              
              
              83Expected
                  return on plan assets
              
              
              (12
              )
              
              (11
              )
              
              (35
              )
              
              (34
              )Amortization
                  of prior service cost
              
              
              (19
              )
              
              (11
              )
              
              (57
              )
              
              (33
              )Recognized
                  net
                  actuarial loss
              
              
              14
              
              
              10
              
              
              42
              
              
              30Net
                  periodic
                  cost
              
              $
              18
              
              $
              25
              
              $
              55
              
              $
              76
  Pension and postretirement benefit obligations are allocated to FirstEnergy’s
        subsidiaries employing the plan participants. FirstEnergy’s subsidiaries
        capitalize employee benefits related to construction projects. The net periodic
        pension costs (credits) and net periodic postretirement benefit costs (including
        amounts capitalized) recognized by each of the Companies for the three months
        and nine months ended September 30, 2006 and 2005 were as
        follows:
 
 **Three
                  Months Ended**
              
              **Nine
                  Months Ended****September
                  30,**
              
              **September
                  30,****Pension
                  Benefit Cost (Credit)**
              
              **2006**
              
              **2005**
              
              **2006**
              
              **2005*****(In
                  millions)***OE
              
              $
              (1.1
              )
              $
              0.2
              
              $
              (3.3
              )
              $
              0.7Penn
              
              
              (0.4
              )
              
              (0.2
              )
              
              (1.2
              )
              
              (0.7
              )CEI
              
              
              1.0
              
              
              0.3
              
              
              2.9
              
              
              1.0TE
              
              
              0.2
              
              
              0.3
              
              
              0.7
              
              
              1.0JCP&L
              
              
              (1.4
              )
              
              (0.3
              )
              
              (4.1
              )
              
              (0.8
              )Met-Ed
              
              
              (1.7
              )
              
              (1.1
              )
              
              (5.2
              )
              
              (3.2
              )Penelec
              
              
              (1.3
              )
              
              (1.3
              )
              
              (4.0
              )
              
              (4.0
              )Other
                  FirstEnergy subsidiaries
              
              
              9.9
              
              
              9.6
              
              
              29.9
              
              
              28.6$
              5.2
              
              $
              7.5
              
              $
              15.7
              
              $
              22.6
 
 **Three
                  Months Ended**
              
              **Nine
                  Months Ended****September
                  30,**
              
              **September
                  30,****Other
                  Postretirement Benefit Cost**
              
              **2006**
              
              **2005**
              
              **2006**
              
              **2005*****(In
                  millions)***OE
              
              $
              3.4
              
              $
              5.8
              
              $
              10.2
              
              $
              17.3Penn
              
              
              0.8
              
              
              1.2
              
              
              2.4
              
              
              3.5CEI
              
              
              2.8
              
              
              3.8
              
              
              8.3
              
              
              11.4TE
              
              
              2.0
              
              
              2.2
              
              
              6.1
              
              
              6.5JCP&L
              
              
              0.6
              
              
              1.5
              
              
              1.8
              
              
              5.7Met-Ed
              
              
              0.7
              
              
              0.4
              
              
              2.2
              
              
              1.2Penelec
              
              
              1.8
              
              
              2.0
              
              
              5.4
              
              
              5.9Other
                  FirstEnergy subsidiaries
              
              
              6.1
              
              
              8.0
              
              
              18.1
              
              
              24.5$
              18.2
              
              $
              24.9
              
              $
              54.5
              
              $
              76.0
 
 
 7
  **9.
        -
        VARIABLE INTEREST ENTITIES**
  FIN 46R addresses the consolidation of VIEs, including special-purpose entities,
        that are not controlled through voting interests or in which the equity
        investors do not bear the entity's residual economic risks and rewards.
        FirstEnergy and its subsidiaries consolidate VIEs when they are determined
        to be
        the VIE's primary beneficiary as defined by FIN 46R.
 
 **Leases**
  FirstEnergy’s consolidated financial statements include PNBV and Shippingport,
        VIEs created in 1996 and 1997, respectively, to refinance debt originally
        issued
        in connection with sale and leaseback transactions. PNBV and Shippingport
        financial data are included in the consolidated financial statements of OE
        and
        CEI, respectively.
  PNBV was established to purchase a portion of the lease obligation bonds
        issued
        in connection with OE’s 1987 sale and leaseback of its interests in the Perry
        Plant and Beaver Valley Unit 2. OE used debt and available funds to purchase
        the
        notes issued by PNBV. Ownership of PNBV includes a 3% equity interest by
        an
        unaffiliated third party and a 3% equity interest held by OES Ventures, a
        wholly
        owned subsidiary of OE. Shippingport was established to purchase all of the
        lease obligation bonds issued in connection with CEI’s and TE’s Bruce Mansfield
        Plant sale and leaseback transaction in 1987. CEI and TE used debt and available
        funds to purchase the notes issued by Shippingport.
 
 OE,
        CEI and TE are
        exposed to losses under the applicable sale-leaseback agreements upon the
        occurrence of certain contingent events that each company considers unlikely
        to
        occur. OE, CEI and TE each have a maximum exposure to loss under these
        provisions of approximately $1 billion, which represents the net amount of
        casualty value payments upon the occurrence of specified casualty events
        that
        render the applicable plant worthless. Under the applicable sale-leaseback
        agreements, OE, CEI and TE have net minimum discounted lease payments of
        $655 million, $95 million and $506 million, respectively, that would
        not be payable if the casualty value payments are made.
 
 **Power
        Purchase Agreements**
  In accordance with FIN 46R, FirstEnergy evaluated its power purchase agreements
        and determined that certain NUG entities may be VIEs to the extent they own
        a
        plant that sells substantially all of its output to the Companies and the
        contract price for power is correlated with the plant’s variable costs of
        production. FirstEnergy, through its subsidiaries JCP&L, Met-Ed and Penelec,
        maintains approximately 30 long-term power purchase agreements with NUG
        entities. The agreements were entered into pursuant to the Public Utility
        Regulatory Policies Act of 1978. FirstEnergy was not involved in the creation
        of, and has no equity or debt invested in, these entities.
  FirstEnergy has determined that for all but eight of these entities, neither
        JCP&L, Met-Ed nor Penelec have variable interests in the entities or the
        entities are governmental or not-for-profit organizations not within the
        scope
        of FIN 46R. JCP&L, Met-Ed or Penelec may hold variable interests in the
        remaining eight entities, which sell their output at variable prices that
        correlate to some extent with the operating costs of the plants. As required
        by
        FIN 46R, FirstEnergy periodically requests from these eight entities the
        information necessary to determine whether they are VIEs or whether JCP&L,
        Met-Ed or Penelec is the primary beneficiary. FirstEnergy has been unable
        to
        obtain the requested information, which in most cases was deemed by the
        requested entity to be proprietary. As such, FirstEnergy applied the scope
        exception that exempts enterprises unable to obtain the necessary information
        to
        evaluate entities under FIN 46R.
 
 Since
        FirstEnergy
        has no equity or debt interests in the NUG entities, its maximum exposure
        to
        loss relates primarily to the above-market costs it incurs for power.
        FirstEnergy expects any above-market costs it incurs to be recovered from
        customers. As of September 30, 2006, the net above-market loss liability
        projected for these eight NUG agreements was $239 million. Purchased power
        costs from these entities during the three months and nine months ended
        September 30, 2006 and 2005 are shown in the following table:
 
 **Three
                      Months Ended**
                  
                  **Nine
                      Months Ended****September
                      30,**
                  
                  **September
                      30,****2006**
                  
                  **2005**
                  
                  **2006**
                  
                  **2005*****(In
                      millions)***JCP&L
                  
                  $
                  29
                  
                  $
                  33
                  
                  $
                  63
                  
                  $
                  74Met-Ed
                  
                  
                  12
                  
                  
                  10
                  
                  
                  45
                  
                  
                  40Penelec
                  
                  
                  8
                  
                  
                  7
                  
                  
                  22
                  
                  
                  21Total
                  
                  $
                  49
                  
                  $
                  50
                  
                  $
                  130
                  
                  $
                  135
 
  8
  **Securitized
        Transition Bonds**
 
 The
        consolidated
        financial statements of FirstEnergy and JCP&L include the results of
        JCP&L Transition Funding and JCP&L Transition Funding II, wholly owned
        limited liability companies of JCP&L. In June 2002, JCP&L Transition
        Funding sold $320 million of transition bonds to securitize the recovery of
        JCP&L's bondable stranded costs associated with the previously divested
        Oyster Creek Nuclear Generating Station. In August 2006, JCP&L Transition
        Funding II sold $182 million of transition bonds to securitize the recovery
        of
        deferred costs associated with JCP&L’s supply of BGS.
 
 JCP&L
        did not
        purchase and does not own any of the transition bonds, which are included
        as
        long-term debt on FirstEnergy's and JCP&L's Consolidated Balance Sheets. The
        transition bonds are the sole obligations of JCP&L Transition Funding and
        JCP&L Transition Funding II and are collateralized by each company’s equity
        and assets, which consists primarily of bondable transition property.
 
 Bondable
        transition
        property represents the irrevocable right under New Jersey law of a utility
        company to charge, collect and receive from its customers, through a
        non-bypassable TBC, the principal amount and interest on transition bonds
        and
        other fees and expenses associated with their issuance. JCP&L sold its
        bondable transition property to JCP&L Transition Funding and JCP&L
        Transition Funding II and, as servicer, manages and administers the bondable
        transition property, including the billing, collection and remittance of
        the
        TBC, pursuant to separate servicing agreements with JCP&L Transition Funding
        and JCP&L Transition Funding II. For the two series of transition bonds,
        JCP&L is entitled to aggregate quarterly servicing fees of $157,000 that is
        payable from TBC collections.
 
 **10.
        -
        COMMITMENTS, GUARANTEES AND CONTINGENCIES**
 
 **(A)**  **GUARANTEES
        AND OTHER ASSURANCES**
  As part of normal business activities, FirstEnergy enters into various
        agreements on behalf of its subsidiaries to provide financial or performance
        assurances to third parties. These agreements include contract guarantees,
        surety bonds and LOCs. As of September 30, 2006, outstanding guarantees and
        other assurances totaled approximately $3.6 billion consisting of contract
        guarantees $2.0 billion, surety bonds $0.2 billion and LOCs
        $1.4 billion.
 
 FirstEnergy
        guarantees energy and energy-related payments of its subsidiaries involved
        in
        energy commodity activities principally to facilitate normal physical
        transactions involving electricity, gas, emission allowances and coal.
        FirstEnergy also provides guarantees to various providers of credit support
        for
        subsidiary financings or refinancings of costs related to the acquisition
        of, or
        improvements to, property, plant and equipment. These agreements legally
        obligate FirstEnergy to fulfill the obligations of those subsidiaries directly
        involved in energy and energy-related transactions or financing where the
        law
        might otherwise limit the counterparties' claims. If demands of a counterparty
        were to exceed the ability of a subsidiary to satisfy existing obligations,
        FirstEnergy's guarantee enables the counterparty's legal claim to be satisfied
        by other FirstEnergy assets. The likelihood is remote that such parental
        guarantees of $0.9 billion (included in the $2.0 billion discussed
        above) as of September 30, 2006 would increase amounts otherwise payable by
        FirstEnergy to meet its obligations incurred in connection with financings
        and
        ongoing energy and energy-related activities.
 
 While
        these types of
        guarantees are normally parental commitments for the future payment of
        subsidiary obligations, subsequent to the occurrence of a credit
        rating-downgrade or “material adverse event” the immediate posting of cash
        collateral or provision of an LOC may be required of the subsidiary. As of
        September 30, 2006, FirstEnergy's maximum exposure under these collateral
        provisions was $487 million.
 
 Most
        of
        FirstEnergy's surety bonds are backed by various indemnities common within
        the
        insurance industry. Surety bonds and related FirstEnergy guarantees of
        $147 million provide additional assurance to outside parties that
        contractual and statutory obligations will be met in a number of areas including
        construction jobs, environmental commitments and various retail transactions.
 
 The
        Companies, with
        the exception of TE and JCP&L, each have a wholly owned subsidiary whose
        borrowings are secured by customer accounts receivable purchased from its
        respective parent company. The CEI subsidiary's borrowings are also secured
        by
        customer accounts receivable purchased from TE. Each subsidiary company has
        its
        own receivables financing arrangement and, as a separate legal entity with
        separate creditors, would have to satisfy its obligations to creditors before
        any of its remaining assets could be available to its parent
        company.
  9
  
 
 **Borrowing****Subsidiary
                  Company**
              
              **Parent
                  Company**
              
              **Capacity*****(In
                  millions)***OES
                  Capital,
                  Incorporated
              
              
              OE
              
              $
              170Centerior
                  Funding Corp.
              
              
              CEI
              
              
              200Penn
                  Power
                  Funding LLC
              
              
              Penn
              
              
              25Met-Ed
                  Funding
                  LLC
              
              
              Met-Ed
              
              
              80Penelec
                  Funding LLC
              
              
              Penelec
              
              
              75$
              550
  FirstEnergy has also guaranteed the obligations of the operators of the TEBSA
        project up to a maximum of $6 million (subject to escalation) under the
        project's operations and maintenance agreement. In connection with the sale
        of
        TEBSA in January 2004, the purchaser indemnified FirstEnergy against any
        loss
        under this guarantee. FirstEnergy has also provided an LOC ($36 million as
        of
        September 30, 2006), which is renewable and declines yearly based upon the
        senior outstanding debt of TEBSA. The LOC was reduced to $27 million on
        October 15, 2006.
 
 **(B)**  **ENVIRONMENTAL
        MATTERS**
  Various federal, state and local authorities regulate FirstEnergy with regard
        to
        air and water quality and other environmental matters. The effects of compliance
        on the Companies with regard to environmental matters could have a material
        adverse effect on FirstEnergy's earnings and competitive position to the
        extent
        that it competes with companies that are not subject to such regulations
        and
        therefore do not bear the risk of costs associated with compliance, or failure
        to comply, with such regulations. Overall, FirstEnergy believes it is in
        compliance with existing regulations but is unable to predict future changes
        in
        regulatory policies and what, if any, the effects of such changes would be.
        FirstEnergy estimates additional capital expenditures for environmental
        compliance of approximately $1.8 billion for 2006 through
        2010.
  FirstEnergy accrues environmental liabilities only when it concludes that
        it is
        probable that it has an obligation for such costs and can reasonably estimate
        the amount of such costs. Unasserted claims are reflected in FirstEnergy’s
        determination of environmental liabilities and are accrued in the period
        that
        they are both probable and reasonably estimable.
  On December 1, 2005, FirstEnergy issued a comprehensive report to shareholders
        regarding air emissions regulations and an assessment of its future risks
        and
        mitigation efforts.
 
 *Clean
        Air Act
        Compliance*
  FirstEnergy is required to meet federally-approved SO 2 emissions
        regulations. Violations of such regulations can result in shutdown of the
        generating unit involved and/or civil or criminal penalties of up to $32,500
        for
        each day the unit is in violation. The EPA has an interim enforcement policy
        for
        SO 2 regulations in Ohio
        that allows for compliance based on a 30-day averaging period. FirstEnergy
        believes it is currently in compliance with this policy, but cannot predict
        what
        action the EPA may take in the future with respect to the interim enforcement
        policy.
  The EPA
        Region
        5 issued a Finding of Violation and NOV to the Bay Shore Power Plant dated
        June
        15, 2006 alleging violations to various sections of the Clean Air Act. A
        meeting
        was held on August 8, 2006 to discuss the alleged violations with the EPA.
        FirstEnergy has disputed those alleged violations based on its Clean Air
        Act
        permit, the Ohio SIP and other information provided at the August 2006 meeting
        with the EPA. The EPA has several enforcement options (administrative compliance
        order, administrative penalty order, and/or judicial, civil or criminal action)
        and has indicated that such option may depend on the time needed to achieve
        and
        demonstrate compliance with the rules alleged to have been
        violated.
 FirstEnergy complies with SO 2 reduction
          requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur
          fuel, generating more electricity from lower-emitting plants, and/or using
          emission allowances. NO X reductions required
          by the 1990 Amendments are being achieved through combustion controls and
          the
          generation of more electricity at lower-emitting plants. In September 1998,
          the
          EPA finalized regulations requiring additional NO X reductions at
          FirstEnergy's facilities. The EPA's NO X Transport Rule
          imposes uniform reductions of NO X emissions (an
          approximate 85% reduction in utility plant NO X emissions from
          projected 2007 emissions) across a region of nineteen states (including
          Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia
          based
          on a conclusion that such NO X emissions are
          contributing significantly to ozone levels in the eastern United States.
          FirstEnergy believes its facilities are also complying with the NO X budgets established
          under SIPs through combustion controls and post-combustion controls, including
          Selective Catalytic Reduction and Selective Non-Catalytic Reduction systems,
          and/or using emission allowances.
  
 
 10
 
 
 
 *National
        Ambient
        Air Quality Standards*
  In July 1997, the EPA promulgated changes in the NAAQS for ozone and fine
        particulate matter. In March 2005, the EPA finalized the CAIR covering a
        total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania)
        and
        the District of Columbia based on proposed findings that air emissions from
        28
        eastern states and the District of Columbia significantly contribute to
        non-attainment of the NAAQS for fine particles and/or the "8-hour" ozone
        NAAQS
        in other states. CAIR provides each affected state until 2006 to develop
        implementing regulations to achieve additional reductions of NO X and SO 2 emissions in two
        phases (Phase I in 2009 for NO X ,
        2010 for
        SO 2 and Phase II in
        2015 for both NO X and SO 2 ).
        FirstEnergy's
        Michigan, Ohio and Pennsylvania fossil-fired generation facilities will be
        subject to caps on SO 2 and NO X emissions, whereas
        its New Jersey fossil-fired generation facility will be subject to only a
        cap on NO X emissions.
        According to the EPA, SO 2 emissions will be
        reduced by 45% (from 2003 levels) by 2010 across the states covered by the
        rule,
        with reductions reaching 73% (from 2003 levels) by 2015, capping SO 2 emissions in
        affected states to just 2.5 million tons annually. NO X emissions will be
        reduced by 53% (from 2003 levels) by 2009 across the states covered by the
        rule,
        with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional NO X cap of 1.3 million
        tons annually. The future cost of compliance with these regulations may be
        substantial and will depend on how they are ultimately implemented by the
        states
        in which FirstEnergy operates affected facilities.
 
 *Mercury
        Emissions*
  In December 2000, the EPA announced it would proceed with the development
        of
        regulations regarding hazardous air pollutants from electric power plants,
        identifying mercury as the hazardous air pollutant of greatest concern. In
        March
        2005, the EPA finalized the CAMR, which provides a cap-and-trade program
        to
        reduce mercury emissions from coal-fired power plants in two phases. Initially,
        mercury emissions will be capped nationally at 38 tons by 2010 (as a
        "co-benefit" from implementation of SO 2 and NO X emission caps under
        the EPA's CAIR program). Phase II of the mercury cap-and-trade program will
        cap
        nationwide mercury emissions from coal-fired power plants at 15 tons per
        year by 2018. However, the final rules give states substantial discretion
        in
        developing rules to implement these programs. In addition, both the CAIR
        and the
        CAMR have been challenged in the United States Court of Appeals for the District
        of Columbia. FirstEnergy's future cost of compliance with these regulations
        may
        be substantial and will depend on how they are ultimately implemented by
        the
        states in which FirstEnergy operates affected facilities.
  The model rules for both CAIR and CAMR contemplate an input-based methodology
        to
        allocate allowances to affected facilities. Under this approach, allowances
        would be allocated based on the amount of fuel consumed by the affected sources.
        FirstEnergy would prefer an output-based generation-neutral methodology in
        which
        allowances are allocated based on megawatts of power produced, since then,
        new
        and non-emitting generating facilities, including renewables and nuclear,
        would
        be entitled to their proportionate share of the allowances. Consequently,
        FirstEnergy will be disadvantaged if these model rules were implemented as
        proposed because FirstEnergy’s substantial reliance on non-emitting (largely
        nuclear) generation is not recognized under the input-based
        allocation.
  Pennsylvania has proposed a new rule to regulate mercury emissions from
        coal-fired power plants that does not provide a cap and trade approach as
        in
        CAMR, but rather follows a command and control approach imposing emission
        limits
        on individual sources. If adopted as proposed, Pennsylvania’s mercury regulation
        would deprive FirstEnergy of mercury emission allowances that were to be
        allocated to the Bruce Mansfield Plant under CAMR and that would otherwise
        be
        available for achieving FirstEnergy system-wide compliance. The future cost
        of
        compliance with these regulations, if adopted and implemented as proposed,
        may
        be substantial.
 
 *W.
        H. Sammis
        Plant*
  In 1999 and 2000, the EPA issued NOV or Compliance Orders to nine utilities
        alleging violations of the Clean Air Act based on operation and maintenance
        of
        44 power plants, including the W. H. Sammis Plant, which was owned at that
        time
        by OE and Penn. In addition, the DOJ filed eight civil complaints against
        various investor-owned utilities, including a complaint against OE and Penn
        in
        the U.S. District Court for the Southern District of Ohio. These cases are
        referred to as New Source Review cases.
  11
   On March 18, 2005, OE and Penn announced that they had reached a settlement
          with
          the EPA, the DOJ and three states (Connecticut, New Jersey, and New York)
          that
          resolved all issues related to the W. H. Sammis Plant New Source Review
          litigation. This settlement agreement was approved by the Court on July
          11,
          2005, and requires reductions of NO X and SO 2 emissions at the W.
          H. Sammis Plant and other coal-fired plants through the installation of
          pollution control devices and provides for stipulated penalties for failure
          to
          install and operate such pollution controls in accordance with that agreement.
          Consequently, if FirstEnergy fails to install such pollution control devices,
          for any reason, including, but not limited to, the failure of any third-party
          contractor to timely meet its delivery obligations for such devices, FirstEnergy
          could be exposed to penalties under the settlement agreement. Capital
          expenditures necessary to meet those requirements are currently estimated
          to be
          $1.5 billion ($400 million of which is expected to be spent in 2007 with
          the
          primary portion of the remaining $1.1 billion expected to be spent in 2008
          and
          2009). On August 26, 2005, FGCO entered into an agreement with Bechtel
          Power
          Corporation under which Bechtel will engineer, procure, and construct air
          quality control systems for the reduction of SO 2 emissions. FGCO
          also entered into an agreement with B&W on August 25, 2006 to supply flue
          gas desulfurization systems for the reduction of SO 2 emissions.
          Selective Catalytic Reduction (SCR) systems for the reduction of NOx emissions
          also are being installed at the W.H. Sammis Plant under a 1999 agreement
          with
          B&W.
  The settlement agreement also requires OE and Penn to spend up to
        $25 million toward environmentally beneficial projects, which include wind
        energy purchased power agreements over a 20-year term. OE and Penn agreed
        to pay
        a civil penalty of $8.5 million. Results for the first quarter of 2005
        included the penalties paid by OE and Penn of $7.8 million and
        $0.7 million, respectively. OE and Penn also recognized liabilities in the
        first quarter of 2005 of $9.2 million and $0.8 million, respectively,
        for probable future cash contributions toward environmentally beneficial
        projects.
 
 *Climate
        Change*
  In December 1997, delegates to the United Nations' climate summit in Japan
        adopted an agreement, the Kyoto Protocol, to address global warming by reducing
        the amount of man-made GHG emitted by developed countries by 5.2% from 1990
        levels between 2008 and 2012. The United States signed the Kyoto Protocol
        in
        1998 but it failed to receive the two-thirds vote required for ratification
        by
        the United States Senate. However, the Bush administration has committed
        the
        United States to a voluntary climate change strategy to reduce domestic GHG
        intensity - the ratio of emissions to economic output - by 18% through 2012.
        The
        EPACT established a Committee on Climate Change Technology to coordinate
        federal
        climate change activities and promote the development and deployment of GHG
        reducing technologies.
  FirstEnergy cannot currently estimate the financial impact of climate change
        policies, although the potential restrictions on CO 2 emissions could
        require significant capital and other expenditures. The CO 2 emissions per KWH
        of electricity generated by FirstEnergy is lower than many regional competitors
        due to its diversified generation sources, which include low or
        non-CO 2 emitting gas-fired
        and nuclear generators.
 
 *Clean
        Water
        Act*
  Various water quality regulations, the majority of which are the result of
        the
        federal Clean Water Act and its amendments, apply to FirstEnergy's plants.
        In
        addition, Ohio, New Jersey and Pennsylvania have water quality standards
        applicable to FirstEnergy's operations. As provided in the Clean Water Act,
        authority to grant federal National Pollutant Discharge Elimination System
        water
        discharge permits can be assumed by a state. Ohio, New Jersey and Pennsylvania
        have assumed such authority.
  On September 7, 2004, the EPA established new performance standards under
        Section 316(b) of the Clean Water Act for reducing impacts on fish and shellfish
        from cooling water intake structures at certain existing large electric
        generating plants. The regulations call for reductions in impingement mortality,
        when aquatic organisms are pinned against screens or other parts of a cooling
        water intake system, and entrainment, which occurs when aquatic species are
        drawn into a facility's cooling water system. FirstEnergy is conducting
        comprehensive demonstration studies, due in 2008, to determine the operational
        measures, equipment or restoration activities, if any, necessary for compliance
        by its facilities with the performance standards. FirstEnergy is unable to
        predict the outcome of such studies. Depending on the outcome of such studies,
        the future cost of compliance with these standards may require material capital
        expenditures.
  12
  
 *Regulation
        of
        Hazardous Waste*
  As a result of the Resource Conservation and Recovery Act of 1976, as amended,
        and the Toxic Substances Control Act of 1976, federal and state hazardous
        waste
        regulations have been promulgated. Certain fossil-fuel combustion waste
        products, such as coal ash, were exempted from hazardous waste disposal
        requirements pending the EPA's evaluation of the need for future regulation.
        The
        EPA subsequently determined that regulation of coal ash as a hazardous waste
        is
        unnecessary. In April 2000, the EPA announced that it will develop national
        standards regulating disposal of coal ash under its authority to regulate
        nonhazardous waste.
 
 The
        Companies have
        been named as PRPs at waste disposal sites, which may require cleanup under
        the
        Comprehensive Environmental Response, Compensation, and Liability Act of
        1980.
        Allegations of disposal of hazardous substances at historical sites and the
        liability involved are often unsubstantiated and subject to dispute; however,
        federal law provides that all PRPs for a particular site are liable on a
        joint
        and several basis. Therefore, environmental liabilities that are considered
        probable have been recognized on the Consolidated Balance Sheet as of
        September 30, 2006, based on estimates of the total costs of cleanup, the
        Companies' proportionate responsibility for such costs and the financial
        ability
        of other unaffiliated entities to pay. In addition, JCP&L has accrued
        liabilities for environmental remediation of former manufactured gas plants
        in
        New Jersey; those costs are being recovered by JCP&L through a
        non-bypassable SBC. Total
        liabilities of
        approximately $73 million (JCP&L - $55 million,
        CEI - $1 million,
        and other subsidiaries - $17 million)
        have been accrued through September 30, 2006.
 
 **(C)**  **OTHER
        LEGAL
        PROCEEDINGS**
 
 *Power
        Outages
        and Related Litigation*
 
 In July 1999, the Mid-Atlantic States experienced a severe heat wave, which
        resulted in power outages throughout the service territories of many electric
        utilities, including JCP&L's territory. In an investigation into the causes
        of the outages and the reliability of the transmission and distribution systems
        of all four of New Jersey’s electric utilities, the NJBPU concluded that there
        was not a prima facie case demonstrating that, overall, JCP&L provided
        unsafe, inadequate or improper service to its customers. Two class action
        lawsuits (subsequently consolidated into a single proceeding) were filed
        in New
        Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU
        companies, seeking compensatory and punitive damages arising from the July
        1999
        service interruptions in the JCP&L territory.
  In August 2002, the trial court granted partial summary judgment to JCP&L
        and dismissed the plaintiffs' claims for consumer fraud, common law fraud,
        negligent misrepresentation, and strict product liability. In November 2003,
        the
        trial court granted JCP&L's motion to decertify the class and denied
        plaintiffs' motion to permit into evidence their class-wide damage model
        indicating damages in excess of $50 million. These class decertification
        and
        damage rulings were appealed to the Appellate Division. The Appellate Division
        issued a decision on July 8, 2004, affirming the decertification of the
        originally certified class, but remanding for certification of a class limited
        to those customers directly impacted by the outages of JCP&L transformers in
        Red Bank, New Jersey. In 2005, JCP&L renewed its motion to decertify the
        class based on a very limited number of class members who incurred damages
        and
        also filed a motion for summary judgment on the remaining plaintiffs’ claims for
        negligence, breach of contract and punitive damages. In July 2006, the New
        Jersey Superior Court dismissed the punitive damage claim and again decertified
        the class based on the fact that a vast majority of the class members did
        not
        suffer damages and those that did would be more appropriately addressed in
        individual actions. Plaintiffs appealed this ruling to the New Jersey Appellate
        Division because it effectively terminates this class action. Briefs are
        being
        prepared and filed, and legal argument is scheduled for late November 2006.
        FirstEnergy is unable to predict the outcome of these matters and no liability
        has been accrued as of September 30, 2006.
  13
   On August 14, 2003, various states and parts of southern Canada experienced
        widespread power outages. The outages affected approximately 1.4 million
        customers in FirstEnergy's service area. The U.S. - Canada Power System Outage
        Task Force’s final report in April 2004 on the outages concluded, among other
        things, that the problems leading to the outages began in FirstEnergy’s Ohio
        service area.Specifically,
        the
        final report concluded, among other things, that the initiation of the
        August 14, 2003 power outages resulted from an alleged failure of both
        FirstEnergy and ECAR to assess and understand perceived inadequacies within
        the
        FirstEnergy system; inadequate situational awareness of the developing
        conditions; and a perceived failure to adequately manage tree growth in certain
        transmission rights of way. The Task Force also concluded that there was
        a
        failure of the interconnected grid's reliability organizations (MISO and
        PJM) to
        provide effective real-time diagnostic support. The final report is publicly
        available through the Department of Energy’s Web site (www.doe.gov). FirstEnergy
        believes that the final report does not provide a complete and comprehensive
        picture of the conditions that contributed to the August 14, 2003 power
        outages and that it does not adequately address the underlying causes of
        the
        outages. FirstEnergy remains convinced that the outages cannot be explained
        by
        events on any one utility's system. The final report contained 46
“recommendations to prevent or minimize the scope of future blackouts.”
Forty-five of those recommendations related to broad industry or policy matters
        while one, including subparts, related to activities the Task Force recommended
        be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct
        the
        causes of the August 14, 2003 power outages. FirstEnergy implemented
        several initiatives, both prior to and since the August 14, 2003 power
        outages, which were independently verified by NERC as complete in 2004 and
        were
        consistent with these and other recommendations and collectively enhance
        the
        reliability of its electric system. FirstEnergy’s implementation of these
        recommendations in 2004 included completion of the Task Force recommendations
        that were directed toward FirstEnergy. FirstEnergy is also proceeding with
        the
        implementation of the recommendations that were to be completed subsequent
        to
        2004 and will continue to periodically assess the FERC-ordered Reliability
        Study
        recommendations for forecasted 2009 system conditions, recognizing revised
        load
        forecasts and other changing system conditions which may impact the
        recommendations. Thus far, implementation of the recommendations has not
        required, nor is expected to require, substantial investment in new or material
        upgrades to existing equipment. The FERC or other applicable government agencies
        and reliability coordinators may, however, take a different view as to
        recommended enhancements or may recommend additional enhancements in the
        future
        as a result of adoption of mandatory reliability standards pursuant to the
        EPACT
        that could require additional material expenditures.
  FirstEnergy companies also are defending six separate complaint cases before
        the
        PUCO relating to the August 14, 2003 power outages. Two cases were
        originally filed in Ohio State courts but were subsequently dismissed for
        lack
        of subject matter jurisdiction and further appeals were unsuccessful. In
        these
        cases the individual complainants—three in one case and four in the other—sought
        to represent others as part of a class action. The PUCO dismissed the class
        allegations, stating that its rules of practice do not provide for class
        action
        complaints. Three other pending PUCO complaint cases were filed by various
        insurance carriers either in their own name as subrogees or in the name of
        their
        insured. In each of these three cases, the carrier seeks reimbursement from
        various FirstEnergy companies (and, in one case, from PJM, MISO and American
        Electric Power Company, Inc., as well) for claims paid to insureds for damages
        allegedly arising as a result of the loss of power on August 14, 2003. The
        listed insureds in these cases, in many instances, are not customers of any
        FirstEnergy company. The sixth case involves the claim of a non-customer
        seeking
        reimbursement for losses incurred when its store was burglarized on
        August 14, 2003. That case has been dismissed.On
        March 7,
        2006, the PUCO issued a ruling, based on motions filed by the parties,
        applicable to all pending cases. Among its various rulings, the PUCO
        consolidated all of the pending outage cases for hearing; limited the litigation
        to service-related claims by customers of the Ohio operating companies;
        dismissed FirstEnergy as a defendant; ruled that the U.S.-Canada Power System
        Outage Task Force Report was not admissible into evidence; and gave the
        plaintiffs additional time to amend their complaints to otherwise comply
        with
        the PUCO’s underlying order.Also, most
        complainants, along with the FirstEnergy companies, filed applications for
        rehearing with the PUCO over various rulings contained in the March 7, 2006
        order. On April 26, 2006, the PUCO granted rehearing to allow the insurance
        company claimants, as insurers, to prosecute their claims in their name so
        long
        as they also identify the underlying insured entities and the Ohio utilities
        that provide their service. The PUCO denied all other motions for rehearing.
        The
        plaintiffs in each case have since filed an amended complaint and the named
        FirstEnergy companies have answered and also have filed a motion to dismiss
        each
        action. On September 27, 2006, the PUCO dismissed certain parties and claims
        and
        otherwise ordered the complaints to go forward to hearing. The cases have
        been
        set for hearing on October 16, 2007.
 On October 10, 2006, various insurance carriers refiled a complaint in
          Cuyahoga
          County Common Pleas Court seeking reimbursement for claims paid to numerous
          insureds who allegedly suffered losses as a result of the August 14, 2003
          outages. All of the insureds appear to be non-customers. The plaintiff
          insurance
          companies are the same claimants in one of the pending PUCO cases. FirstEnergy,
          the
          Ohio Companies and Penn were served on October 27, 2006, and expect to seek
          summary dismissal of these cases based on the prior court rulings noted
          above.No estimate of potential liability is available for any of these
          cases.
  14
 FirstEnergy was also named, along with several other entities, in a complaint
        in
        New Jersey State Court. The allegations against FirstEnergy were based, in
        part,
        on an alleged failure to protect the citizens of Jersey City from an electrical
        power outage. None of FirstEnergy’s subsidiaries serve customers in Jersey City.
        A responsive pleading has been filed. On April 28, 2006, the Court granted
        FirstEnergy's motion to dismiss. The plaintiff has not appealed.
  FirstEnergy is vigorously defending these actions, but cannot predict the
        outcome of any of these proceedings or whether any further regulatory
        proceedings or legal actions may be initiated against the Companies. Although
        unable to predict the impact of these proceedings, if FirstEnergy or its
        subsidiaries were ultimately determined to have legal liability in connection
        with these proceedings, it could have a material adverse effect on FirstEnergy's
        or its subsidiaries' financial condition, results of operations and cash
        flows.
 
 *Nuclear
        Plant
        Matters*
  On January 20, 2006, FENOC announced that it had entered into a deferred
        prosecution agreement with the U.S. Attorney’s Office for the Northern District
        of Ohio and the Environmental Crimes Section of the Environment and Natural
        Resources Division of the DOJ related to FENOC’s communications with the NRC
        during the fall of 2001 in connection with the reactor head issue at the
        Davis-Besse Nuclear Power Station. Under the agreement, which expires on
        December 31, 2006, the United States acknowledged FENOC’s extensive
        corrective actions at Davis-Besse, FENOC’s cooperation during investigations by
        the DOJ and the NRC, FENOC’s pledge of continued cooperation in any related
        criminal and administrative investigations and proceedings, FENOC’s
        acknowledgement of responsibility for the behavior of its employees, and
        its
        agreement to pay a monetary penalty. The DOJ will refrain from seeking an
        indictment or otherwise initiating criminal prosecution of FENOC for all
        conduct
        related to the statement of facts attached to the deferred prosecution
        agreement, as long as FENOC remains in compliance with the agreement, which
        FENOC fully intends to do. FENOC paid a monetary penalty of $28 million
        (not deductible for income tax purposes) which reduced FirstEnergy's earnings
        by
        $0.09 per common share in the fourth quarter of 2005.
  On April 21, 2005, the NRC issued a NOV and proposed a $5.45 million
        civil penalty related to the degradation of the Davis-Besse reactor vessel
        head
        issue discussed above. FirstEnergy accrued $2 million for a potential fine
        prior to 2005 and accrued the remaining liability for the proposed fine during
        the first quarter of 2005. On September 14, 2005, FENOC filed its response
        to the NOV with the NRC. FENOC accepted full responsibility for the past
        failure
        to properly implement its boric acid corrosion control and corrective action
        programs. The NRC NOV indicated that the violations do not represent current
        licensee performance. FirstEnergy paid the penalty in the third quarter of
        2005.
        On January 23, 2006, FENOC supplemented its response to the NRC's NOV on
        the Davis-Besse head degradation to reflect the deferred prosecution agreement
        that FENOC had reached with the DOJ.
  On August 12, 2004, the NRC notified FENOC that it would increase its
        regulatory oversight of the Perry Nuclear Power Plant as a result of problems
        with safety system equipment over the preceding two years and the licensee's
        failure to take prompt and corrective action. FENOC operates the Perry Nuclear
        Power Plant.
  On April 4, 2005, the NRC held a public meeting to discuss FENOC’s
        performance at the Perry Nuclear Power Plant as identified in the NRC's annual
        assessment letter to FENOC. Similar public meetings are held with all nuclear
        power plant licensees following issuance by the NRC of their annual assessments.
        According to the NRC, overall the Perry Nuclear Power Plant operated "in
        a
        manner that preserved public health and safety" even though it remained under
        heightened NRC oversight. During the public meeting and in the annual
        assessment, the NRC indicated that additional inspections will continue and
        that
        the plant must improve performance to be removed from the Multiple/Repetitive
        Degraded Cornerstone Column of the Action Matrix.
  On
        September 28, 2005, the NRC sent a CAL to FENOC describing commitments that
        FENOC had made to improve the performance at the Perry Nuclear Power Plant
        and
        stated that the CAL would remain open until substantial improvement was
        demonstrated. The CAL was anticipated as part of the NRC's Reactor Oversight
        Process. In the NRC's 2005 annual assessment letter dated March 2, 2006 and
        associated meetings to discuss the performance of the Perry Nuclear Power
        Plant
        on March 14, 2006, the NRC again stated that the Perry Nuclear Power Plant
        continued to operate in a manner that "preserved public health and safety."
        However, the NRC also stated that increased levels of regulatory oversight
        would
        continue until sustained improvement in the performance of the facility was
        realized. If performance does not improve, the NRC has a range of options
        under
        the Reactor Oversight Process, from increased oversight to possible impact
        to
        the plant’s operating authority. Although FirstEnergy is unable to predict the
        impact of the ultimate disposition of this matter, it could have a material
        adverse effect on FirstEnergy's or its subsidiaries' financial condition,
        results of operations and cash flows.
  15
  *Other
        Legal
        Matters*
  There are various lawsuits, claims (including claims for asbestos exposure)
        and
        proceedings related to FirstEnergy's normal business operations pending against
        FirstEnergy and its subsidiaries. The other potentially material items not
        otherwise discussed above are described below.
 
 On October 20, 2004, FirstEnergy was notified by the SEC that the
        previously disclosed informal inquiry initiated by the SEC's Division of
        Enforcement in September 2003 relating to the restatements in August 2003
        of
        previously reported results by FirstEnergy and the Ohio Companies, and the
        Davis-Besse extended outage, have become the subject of a formal order of
        investigation. The SEC's formal order of investigation also encompasses issues
        raised during the SEC's examination of FirstEnergy and the Companies under
        the
        now repealed PUHCA. Concurrent with this notification, FirstEnergy received
        a
        subpoena asking for background documents and documents related to the
        restatements and Davis-Besse issues. On December 30, 2004, FirstEnergy
        received a subpoena asking for documents relating to issues raised during
        the
        SEC's PUHCA examination. On August 24, 2005, additional information was
        requested regarding Davis-Besse-related disclosures, which has been provided.
        FirstEnergy has cooperated fully with the informal inquiry and continues
        to do
        so with the formal investigation.
  On August 22, 2005, a class action complaint was filed against OE in
        Jefferson County, Ohio Common Pleas Court, seeking compensatory and punitive
        damages to be determined at trial based on claims of negligence and eight
        other
        tort counts alleging damages from W.H. Sammis Plant air emissions. The two
        named
        plaintiffs are also seeking injunctive relief to eliminate harmful emissions
        and
        repair property damage and the institution of a medical monitoring program
        for
        class members. On October 18, 2006, the Ohio Supreme Court transferred this
        case to a Tuscarawas County Common Pleas Court judge due to concerns over
        potential class membership by the Jefferson County Common Pleas
        Court.
  JCP&L's bargaining unit employees filed a grievance challenging JCP&L's
        2002 call-out procedure that required bargaining unit employees to respond
        to
        emergency power outages. On May 20, 2004, an arbitration panel concluded
        that the call-out procedure violated the parties' collective bargaining
        agreement. At the conclusion of the June 1, 2005 hearing, the arbitration
        panel decided not to hear testimony on damages and closed the proceedings.
        On
        September 9, 2005, the arbitration panel issued an opinion to award
        approximately $16 million to the bargaining unit employees. On February 6,
        2006, a federal district court granted a union motion to dismiss as premature
        a
        JCP&L appeal of the award filed on October 18, 2005. JCP&L intends
        to re-file an appeal again in federal district court once the damages associated
        with this case are identified at an individual employee level. JCP&L
        recognized a liability for the potential $16 million award in
        2005.
  The City of Huron filed a complaint against OE with the PUCO challenging
        the
        ability of electric distribution utilities to collect transition charges
        from a
        customer of a newly-formed municipal electric utility. The complaint was
        filed
        on May 28, 2003, and OE timely filed its response on June 30, 2003. In
        a related filing, the Ohio Companies filed for approval with the PUCO of
        a
        tariff that would specifically allow the collection of transition charges
        from
        customers of municipal electric utilities formed after 1998. Both filings
        were
        consolidated for hearing and decision. An adverse ruling could negatively
        affect
        full recovery of transition charges by the utility. Hearings on the matter
        were
        held in August 2005. Initial briefs from all parties were filed on
        September 22, 2005 and reply briefs were filed on October 14, 2005. On
        May 10, 2006, the PUCO issued its Opinion and Order dismissing the City’s
        complaint and approving the related tariffs, thus affirming OE’s entitlement to
        recovery of its transition charges. The City of Huron
        filed an application for rehearing of the PUCO’s decision on June 9, 2006
        and OE filed a memorandum in opposition to that application on June 19,
        2006. The PUCO denied the City’s application for rehearing on June 28, 2006. The
        City of Huron has taken no further action and the period for filing an appeal
        has expired.
  If it were ultimately determined that FirstEnergy or its subsidiaries have
        legal
        liability or are otherwise made subject to liability based on the above matters,
        it could have a material adverse effect on FirstEnergy's or its subsidiaries'
        financial condition, results of operations and cash flows.
 
 **(D)**  **ACCELERATED
        SHARE REPURCHASE PROGRAM**
  On August 9, 2006, FirstEnergy entered into an accelerated share repurchase
        agreement with a financial institution counterparty under which FirstEnergy
        repurchased 10.6 million shares, or approximately 3.2%, of its outstanding
        common stock on August 10, 2006 at an initial price of $56.44 per share,
        or a
        total initial purchase price of $600 million. This forward sale contract
        is
        being accounted for as an equity instrument. The final purchase price is
        subject
        to a contingent purchase price adjustment based on the average of the daily
        volume-weighted average prices over a subsequent purchase period of up to
        seven
        months, as well as other purchase price adjustments in the event of an
        extraordinary cash dividend or other dilution events. The price adjustment
        can
        be settled, at FirstEnergy’s option, in cash or in shares of its common stock.
        The size of any settlement amount and whether it is to be paid or received
        by
        FirstEnergy will depend upon the average of the daily volume-weighted average
        prices of the shares as calculated by the counterparty under the program.
        The
        settlement is expected to occur in the first quarter of 2007.
  16
  
 The
        accelerated
        share repurchase was completed under a program authorized by the Board of
        Directors on June 20, 2006 to repurchase up to 12 million shares of
        common stock. At management’s discretion, additional shares may be acquired
        under the program on the open market or through privately negotiated
        transactions, subject to market conditions and other factors. The Board’s
        authorization of the repurchase program does not require FirstEnergy to make
        any
        further repurchases of shares and the program may be terminated at any
        time.
 
 **11.
        -
        REGULATORY MATTERS**
 
 **RELIABILITY
        INITIATIVES**
 
 In late 2003 and early 2004, a series of letters, reports and recommendations
        were issued from various entities, including governmental, industry and ad
        hoc
        reliability entities (PUCO, FERC, NERC and the U.S. - Canada Power System
        Outage
        Task Force) regarding enhancements to regional reliability. In 2004, FirstEnergy
        completed implementation of all actions and initiatives related to enhancing
        area reliability, improving voltage and reactive management, operator readiness
        and training and emergency response preparedness recommended for completion
        in
        2004. On July 14, 2004, NERC independently verified that FirstEnergy had
        implemented the various initiatives to be completed by June 30 or summer
        2004, with minor exceptions noted by FirstEnergy, which exceptions are now
        essentially complete. FirstEnergy is proceeding with the implementation of
        the
        recommendations that were to be completed subsequent to 2004 and will continue
        to periodically assess the FERC-ordered Reliability Study recommendations
        for
        forecasted 2009 system conditions, recognizing revised load forecasts and
        other
        changing system conditions which may impact the recommendations. Thus far,
        implementation of the recommendations has not required, nor is expected to
        require, substantial investment in new equipment or material upgrades to
        existing equipment. The FERC or other applicable government agencies and
        reliability coordinators may, however, take a different view as to recommended
        enhancements or may recommend additional enhancements in the future as the
        result of adoption of mandatory reliability standards pursuant to the EPACT,
        all
        of which could require additional, material expenditures.
 
 As
        a result of
        outages experienced in JCP&L’s service area in 2002 and 2003, the NJBPU had
        implemented reviews into JCP&L’s service reliability. In 2004, the NJBPU
        adopted an MOU that set out specific tasks related to service reliability
        to be
        performed by JCP&L and a timetable for completion and endorsed JCP&L’s
        ongoing actions to implement the MOU. On June 9, 2004, the NJBPU approved a
        Stipulation that incorporates the final report of an SRM who made
        recommendations on appropriate courses of action necessary to ensure system-wide
        reliability. The Stipulation also incorporates the Executive Summary and
        Recommendation portions of the final report of a focused audit of JCP&L’s
        Planning and Operations and Maintenance programs and practices (Focused Audit).
        A final order in the Focused Audit docket was issued by the NJBPU on
        July 23, 2004. On February 11, 2005, JCP&L met with the DRA to
        discuss reliability improvements. The SRM completed his work and issued his
        final report to the NJBPU on June 1, 2006. A meeting was held between JCP&L
        and the NJBPU on June 29, 2006 to discuss the SRM’s final report. JCP&L
        filed a comprehensive response to the NJBPU on July 14, 2006. JCP&L
        continues to file compliance reports reflecting activities associated with
        the
        MOU and Stipulation.
 
 The EPACT provides for the creation of an ERO to establish and enforce
        reliability standards for the bulk power system, subject to FERC’s review. On
        February 3, 2006, the FERC adopted a rule establishing certification
        requirements for the ERO, as well as regional entities envisioned to assume
        monitoring responsibility for the new reliability standards. The FERC issued
        an
        order on rehearing on March 30, 2006, providing certain clarifications and
        essentially affirming the rule.
 
 The NERC has been preparing the implementation aspects of reorganizing its
        structure to meet the FERC’s certification requirements for the ERO. The NERC
        made a filing with the FERC on April 4, 2006 to obtain certification as the
        ERO and to obtain FERC approval of delegation agreements with regional
        reliability organizations (regional entities). The new FERC rule referred
        to
        above, further provides for reorganizing regional entities that would replace
        the current regional councils and for rearranging their relationship with
        the
        ERO. The “regional entity” may be delegated authority by the ERO, subject to
        FERC approval, for enforcing reliability standards adopted by the ERO and
        approved by the FERC. The ERO filing was noticed on April 7, 2006 and comments
        and reply comments were filed in May, June and July 2006. On July 20, 2006,
        the
        FERC certified the NERC as the ERO to implement the provisions of Section
        215 of
        the Federal Power Act and directed the NERC to make a compliance filing within
        90 days addressing such issues as the regional delegation agreements. The
        NERC
        made its compliance filing in October 2006. This filing is pending before
        the
        FERC.
  17
  
 On
            April 4, 2006,
            NERC also submitted a filing with the FERC seeking approval of mandatory
            reliability standards. These reliability standards are based, with some
            modifications and additions, on the current NERC Version O reliability
            standards. The reliability standards filing was noticed by the FERC on
            April 18,
            2006. In that notice, the FERC announced its intent to issue a Notice
            of
            Proposed Rulemaking on the proposed reliability standards at a future
            date. On
            May 11, 2006, the FERC staff released a preliminary assessment that cited
            many deficiencies in the proposed reliability standards. The NERC and
            industry
            participants filed comments in response to the Staff’s preliminary assessment.
            The FERC held a technical conference on the proposed reliability standards
            on
            July 6, 2006. The FERC issued a Notice of Proposed Rulemaking on the
            proposed
            reliability standards on October 20, 2006. The FERC voted to adopt 83 of
            the proposed 107 reliability standards. The FERC asked the NERC to make
            technical improvements to 62 of the 83 standards approved. The 24 standards
            that
            were not adopted remain pending at the FERC awaiting further clarification
            and
            filings by the NERC and regional entities. The FERC also provided additional
            clarification on the proposed application of final standards in the NOPR.
            Interested parties will be given the opportunity to comment on the NOPR
            within
            60 days of its publication in the Federal Register. Mandatory reliability
            standards are expected to be in place by the summer of 2007. In a separate
            order
            issued October 24, 2006, the FERC approved NERC’s 2007 budget and business
            plan subject to certain compliance filings.
 The
        ECAR,
        Mid-Atlantic Area Council, and Mid-American Interconnected Network reliability
        councils have completed the consolidation of these regions into a single
        new
        regional reliability organization known as ReliabilityFirst Corporation.
        ReliabilityFirst began operations as a regional reliability council under
        NERC
        on January 1, 2006 and intends to file and obtain certification consistent
        with the final rule as a “regional entity” under the ERO during 2006. All of
        FirstEnergy’s facilities are located within the ReliabilityFirst
        region.
 
 On May 2, 2006, the NERC Board of Trustees adopted eight new cyber security
        standards that replaced interim standards put in place in the wake of the
        September 11, 2001 terrorist attacks, and thirteen additional reliability
        standards. The security standards became effective on June 1, 2006, and the
        remaining standards will become effective throughout 2006 and 2007. NERC
        intends
        to file the standards with the FERC and relevant Canadian authorities for
        approval, but
        the cyber security standards were not included in the October 20, 2006
        NOPR.
 
 FirstEnergy
        believes
        it is in compliance with all current NERC reliability standards.
        However, based
        upon a review
        of the October 20, 2006 NOPR, it appears that the FERC will
        adopt stricter reliability standards than those contained in the current
        NERC
        standards. The financial impact of complying with the new standards cannot
        be
        determined at this time. However, the EPACT required that all prudent costs
        incurred to comply with the new reliability standards be recovered in rates.
        If
        FirstEnergy is unable to meet the reliability standards for the bulk power
        system in the future, it could have a material adverse effect on the Company’s
        and its subsidiaries’ financial condition, results of operations and cash
        flows.
 
 **OHIO**
  On
        October 21, 2003,
        the Ohio Companies filed their RSP case with the PUCO. On August 5, 2004,
        the
        Ohio Companies accepted the RSP as modified and approved by the PUCO in an
        August 4, 2004 Entry on Rehearing, subject to a CBP. The RSP was intended
        to
        establish generation service rates beginning January 1, 2006, in response
        to the
        PUCO’s concerns about price and supply uncertainty following the end of the Ohio
        Companies' transition plan market development period. In October 2004, the
        OCC
        and NOAC filed appeals with the Supreme Court of Ohio to overturn the original
        June 9, 2004 PUCO order in the proceeding as well as the associated entries
        on
        rehearing. On May 3, 2006, the Supreme Court of Ohio issued an opinion affirming
        the PUCO's order with respect to the approval of the rate stabilization charge,
        approval of the shopping credits, the granting of interest on shopping credit
        incentive deferral amounts, and approval of the Ohio Companies’ financial
        separation plan. It remanded back to the PUCO the matter of ensuring the
        availability of sufficient means for customer participation in the competitive
        marketplace. The RSP contained a provision that permitted the Ohio Companies
        to
        withdraw and terminate the RSP in the event that the PUCO, or the Supreme
        Court
        of Ohio, rejected all or part of the RSP. In such event, the Ohio Companies
        have
        30 days from the final order or decision to provide notice of termination.
        On
        July 20, 2006 the Ohio Companies filed with the PUCO a Request to Initiate
        a
        Proceeding on Remand. In their Request, the Ohio Companies provided notice
        of
        termination to those provisions of the RSP subject to termination, subject
        to
        being withdrawn, and also set forth a framework for addressing the Supreme
        Court
        of Ohio’s findings on customer participation, requesting the PUCO to initiate a
        proceeding to consider the Ohio Companies’ proposal. If the PUCO approves a
        resolution to the issues raised by the Supreme Court of Ohio that is acceptable
        to the Ohio Companies, the Ohio Companies’ termination will be withdrawn and
        considered to be null and void. Separately, the OCC and NOAC also submitted
        to
        the PUCO on July 20, 2006 a conceptual proposal dealing with the issue raised
        by
        the Supreme Court of Ohio. On July 26, 2006, the PUCO issued an Entry
        acknowledging the July 20, 2006 filings of the Ohio Companies and the OCC
        and
        NOAC, and giving the Ohio Companies 45 days to file a plan in a new docket
        to
        address the Court’s concern. On September 19, 2006, the PUCO issued an
        Entry granting the Ohio Companies’ motion for extension of time to file the
        remand proposal. The Ohio Companies filed their RSP Remand CBP on
        September 29, 2006. No further proceedings have been scheduled at this
        time.
  18
  
 The Ohio Companies filed an application and stipulation with the PUCO on
        September 9, 2005 seeking approval of the RCP, a supplement to the RSP. On
        November 4, 2005, the Ohio Companies filed a supplemental stipulation with
        the
        PUCO, which constituted an additional component of the RCP filed on September
        9,
        2005. Major provisions of the RCP include:
 
 ●
              Maintaining
                  the existing level of base distribution rates through December 31,
                  2008 for OE and TE, and April 30, 2009 for CEI;●
              Deferring
                  and
                  capitalizing for future recovery (over a 25-year period) with carrying
                  charges certain distribution costs to be incurred during the period
                  January 1, 2006 through December 31, 2008, not to exceed
                  $150 million in each of the three years;●
              Adjusting
                  the
                  RTC and extended RTC recovery periods and rate levels so that full
                  recovery of authorized costs will occur as of December 31, 2008 for
                  OE and TE and as of December 31, 2010 for CEI;●
              Reducing
                  the
                  deferred shopping incentive balances as of January 1, 2006 by up to
                  $75 million for OE, $45 million for TE, and $85 million for CEI
                  by accelerating the application of each respective company's accumulated
                  cost of removal regulatory liability; and●
              Recovering
                  increased fuel costs (compared to a 2002 baseline) of up to
                  $75 million, $77 million, and $79 million, in 2006, 2007,
                  and 2008, respectively, from all OE and TE distribution and transmission
                  customers through a fuel recovery mechanism. OE, TE, and CEI may
                  defer and
                  capitalize (for recovery over a 25-year period) increased fuel
                  costs above
                  the amount collected through the fuel recovery
                  mechanism.
 
 On January 4, 2006, the PUCO approved, with modifications, the Ohio Companies’
RCP to supplement the RSP to provide customers with more certain rate levels
        than otherwise available under the RSP during the plan period. On
        January 10,
        2006, the Ohio Companies filed a Motion for Clarification of the PUCO order
        approving the RCP. The Ohio Companies sought clarity on issues related to
        distribution deferrals, including requirements of the review process, timing
        for
        recognizing certain deferrals and definitions of the types of qualified
        expenditures. The Ohio Companies also sought confirmation that the list of
        deferrable distribution expenditures originally included in the revised
        stipulation fall within the PUCO order definition of qualified expenditures.
        On
        January 25, 2006, the PUCO issued an Entry on Rehearing granting in part,
        and denying in part, the Ohio Companies’ previous requests and clarifying issues
        referred to above. The PUCO granted the Ohio Companies’ requests
        to:
 
 ●
              Recognize
                  fuel
                  and distribution deferrals commencing January 1,
                  2006;●
              Recognize
                  distribution deferrals on a monthly basis prior to review by the
                  PUCO
                  Staff;●
              Clarify
                  that
                  the types of distribution expenditures included in the Supplemental
                  Stipulation may be deferred; and●
              Clarify
                  that
                  distribution expenditures do not have to be “accelerated” in order to be
                  deferred.
 
 The PUCO approved the Ohio Companies’ methodology for determining distribution
        deferral amounts, but denied the Motion in that the PUCO Staff must verify
        the
        level of distribution expenditures contained in current rates, as opposed
        to
        simply accepting the amounts contained in the Ohio Companies’ Motion. On
        February 3, 2006, several other parties filed applications for rehearing on
        the PUCO's January 4, 2006 Order. The Ohio Companies responded to the
        applications for rehearing on February 8, 2006. In an Entry on Rehearing
        issued by the PUCO on March 1, 2006, all motions for rehearing were denied.
        Certain of these parties have subsequently filed notices of appeal with the
        Supreme Court of Ohio alleging various errors made by the PUCO in its order
        approving the RCP. The Ohio Companies’ Motion to Intervene in the appeals was
        granted by the Supreme Court on June 8, 2006. The Appellants’ Merit Briefs were
        filed at the Supreme Court on July 5, 2006. The Appellees include the PUCO
        and
        the Ohio Companies. The Appellees’ Merit Briefs were filed on August 24, 2006
        and the Appellants’ Reply Briefs were filed on September 21, 2006. The OCC
        filed an amicus brief on August 4, 2006, which the Ohio Companies moved to
        strike as improperly filed. The Supreme Court denied the Ohio Companies’ motion
        on October 18, 2006.
  19
  On December 30, 2004, the Ohio Companies filed with the PUCO two
        applications related to the recovery of transmission and ancillary service
        related costs. The first application sought recovery of these costs beginning
        January 1, 2006. The Ohio Companies requested that these costs be recovered
        through a rider that would be effective on January 1, 2006 and adjusted
        each July 1 thereafter. The parties reached a settlement agreement that was
        approved by the PUCO on August 31, 2005. The incremental transmission and
        ancillary service revenues recovered from January 1 through June 30,
        2006 were approximately $61 million. That amount included the recovery of a
        portion of the 2005 deferred MISO expenses as described below. On April 27,
        2006, the Ohio Companies filed the annual update rider to determine revenues
        ($139 million) from July 2006 through June 2007. The filed rider went into
        effect on July 1, 2006.
  The second application sought authority to defer costs associated with
        transmission and ancillary service related costs incurred during the period
        October 1, 2003 through December 31, 2005. On May 18, 2005, the
        PUCO granted the accounting authority for the Ohio Companies to defer
        incremental transmission and ancillary service-related charges incurred as
        a
        participant in MISO, but only for those costs incurred during the period
        December 30, 2004 through December 31, 2005. Permission to defer costs
        incurred prior to December 30, 2004 was denied. The PUCO also authorized
        the Ohio Companies to accrue carrying charges on the deferred balances. On
        August 31, 2005, the OCC appealed the PUCO's decision. On
        January 20,
        2006, the OCC sought rehearing of the PUCO’s approval of the recovery of
        deferred costs through the rider during the period January 1, 2006 through
        June 30, 2006. The PUCO denied the OCC's application on February 6,
        2006. On March 23, 2006, the OCC appealed the PUCO's order to the Ohio
        Supreme Court. On March 27, 2006, the OCC filed a motion to consolidate
        this appeal with the deferral appeals discussed above and to postpone oral
        arguments in the deferral appeal until after all briefs are filed in this
        most
        recent appeal of the rider recovery mechanism. On
        March 20, 2006,
        the Ohio Supreme Court, on its own motion, consolidated the OCC's appeal
        of the
        Ohio Companies' case with a similar case involving Dayton Power & Light
        Company. Oral arguments were heard on May 10, 2006. The Ohio Companies are
        awaiting a final ruling from the Ohio Supreme Court, which is expected before
        the end of 2006.
 
 **PENNSYLVANIA**
  A February 2002 Commonwealth Court of Pennsylvania decision affirmed the
        June
        2001 PPUC decision regarding approval of the FirstEnergy/GPU merger, remanded
        the issues of quantification and allocation of merger savings to the PPUC
        and
        denied Met-Ed and Penelec the rate relief initially approved in the PPUC
        decision. On October 2, 2003, the PPUC issued an order concluding that the
        Commonwealth Court reversed the PPUC’s June 2001 order in its entirety. In
        accordance with the PPUC's direction, Met-Ed and Penelec filed supplements
        to
        their tariffs that became effective in October 2003 and that reflected the
        CTC
        rates and shopping credits in effect prior to the June 2001 order. Met-Ed’s
        and Penelec’s combined portion of total net merger savings during 2001 - 2004 is
        estimated to be approximately $51 million. A procedural schedule was
        established by the ALJ on January 17, 2006 and the companies filed initial
        testimony on March 1, 2006. On May 4, 2006, the PPUC consolidated this
        proceeding with the April 10, 2006 comprehensive rate filing proceeding
        discussed below. Met-Ed and Penelec are unable to predict the outcome of
        this
        matter.
  In an October 16, 2003 order, the PPUC approved June 30, 2004 as the
        date for Met-Ed's and Penelec's NUG trust fund refunds. The PPUC order also
        denied their accounting treatment request regarding the CTC rate/shopping
        credit
        swap by requiring Met-Ed and Penelec to treat the stipulated CTC rates that
        were
        in effect from January 1, 2002 on a retroactive basis. On October 22,
        2003, Met-Ed and Penelec filed an Objection with the Commonwealth Court asking
        that the Court reverse this PPUC finding; a Commonwealth Court judge
        subsequently denied their Objection on October 27, 2003 without
        explanation. On October 31, 2003, Met-Ed and Penelec filed an Application
        for Clarification of the Court order with the Commonwealth Court, a Petition
        for
        Review of the PPUC's October 2 and October 16, 2003 Orders, and an
        Application for Reargument, if the judge, in his clarification order, indicates
        that Met-Ed's and Penelec's Objection was intended to be denied on the merits.
        The Reargument Brief before the Commonwealth Court was filed on January 28,
        2005. Oral arguments were held on June 8, 2006. On July 19, 2006, the
        Commonwealth Court issued its decision affirming the PPUC’s prior orders.
        Although the decision denied the appeal of Met-Ed and Penelec, they had
        previously accounted for the treatment of costs required by the PPUC’s October
        2003 orders.
  Met-Ed and Penelec purchase a portion of their PLR requirements from FES
        through
        a wholesale power sales agreement. Under this agreement, FES retains the
        supply
        obligation and the supply profit and loss risk for the portion of power supply
        requirements not self-supplied by Met-Ed and Penelec under their contracts
        with
        NUGs and other unaffiliated suppliers. The FES arrangement reduces Met-Ed's
        and
        Penelec's exposure to high wholesale power prices by providing power at a
        fixed
        price for their uncommitted PLR energy costs during the term of the agreement
        with FES. The wholesale power sales agreement with FES could automatically
        be
        extended for each successive calendar year unless any party elects to cancel
        the
        agreement by November 1 of the preceding year. On November 1, 2005, FES and
        the other parties thereto amended the agreement to provide FES the right
        in 2006
        to terminate the agreement at any time upon 60 days notice. On
        April 7, 2006, the parties to the wholesale power sales agreement entered
        into a Tolling Agreement that arises out of FES’ notice to Met-Ed and Penelec
        that FES elected to exercise its right to terminate the wholesale power sales
        agreement effective midnight December 31, 2006, because that agreement is
        not economically sustainable to FES.
  20
  
 In lieu of allowing such termination to become effective as of December 31,
        2006, the parties agreed, pursuant to the Tolling Agreement, to amend the
        wholesale power sales agreement to provide as follows:
 
 1.  The
        termination
        provisions of the wholesale power sales agreement will be tolled for one
        year
        until December 31, 2007, provided that during such tolling
        period:
 a.  FES
        will be
        permitted to terminate the wholesale power sales agreement at any time with
        sixty days written notice;
 b.  Met-Ed
        and Penelec
        will procure through arrangements other than the wholesale power sales agreement
        beginning December 1, 2006 and ending December 31, 2007, approximately
        33% of the amounts of capacity and energy necessary to satisfy their PLR
        obligations for which Committed Resources (i.e., non-utility generation under
        contract to Met-Ed and Penelec, Met-Ed- and Penelec-owned generating facilities,
        purchased power contracts and distributed generation) have not been obtained;
        and
 c.  FES
        will not be
        obligated to supply additional quantities of capacity and energy in the event
        that a supplier of Committed Resources defaults on its supply
        agreement;
 
 2.  During
        the tolling
        period, FES will not act as an agent for Met-Ed or Penelec in procuring the
        services under 1.(b) above; and
 
 3.  The
        pricing
        provision of the wholesale power sales agreement shall remain unchanged provided
        Met-Ed and Penelec comply with the provisions of the Tolling Agreement and
        any
        applicable provision of the wholesale power sales agreement.
  In the event that FES elects not to terminate the wholesale power sales
        agreement effective midnight December 31, 2007, similar tolling agreements
        effective after December 31, 2007 are expected to be considered by FES for
        subsequent years if Met-Ed and Penelec procure through arrangements other
        than
        the wholesale power sales agreement approximately 64%, 83% and 95% of the
        additional amounts of capacity and energy necessary to satisfy their PLR
        obligations for 2008, 2009 and 2010, respectively, for which Committed Resources
        have not been obtained from the market. On September 26, 2006, Met-Ed and
        Penelec successfully conducted a competitive RFP for 33% of their PLR obligation
        for which Committed Resources have not been obtained for the period
        December 1, 2006 through December 31, 2008.
  The wholesale power sales agreement, as modified by the Tolling Agreement,
        requires Met-Ed and Penelec to satisfy the portion of their PLR obligations
        currently supplied by FES from unaffiliated suppliers at prevailing prices,
        which are likely to be higher than the current price charged by FES under
        the
        current agreement and, as a result, Met-Ed’s and Penelec’s purchased power costs
        could materially increase. If Met-Ed and Penelec were to replace the entire
        FES
        supply at current market power prices without corresponding regulatory
        authorization to increase their generation prices to customers, each company
        would likely incur a significant increase in operating expenses and experience
        a
        material deterioration in credit quality metrics. Under such a scenario,
        each
        company's credit profile would no longer be expected to support an investment
        grade rating for its fixed income securities. There can be no assurance,
        however, that if FES ultimately determines to terminate, further reduce,
        or
        significantly modify the agreement, timely regulatory relief will be granted
        by
        the PPUC pursuant to the April 10, 2006 comprehensive rate filing discussed
        below, or, to the extent granted, adequate to mitigate such adverse
        consequences.
 
 Met-Ed
        and Penelec
        made a comprehensive rate filing with the PPUC on April 10, 2006 that
        addresses a number of transmission, distribution and supply issues. If Met-Ed's
        and Penelec's preferred approach involving accounting deferrals is approved,
        the
        filing would increase annual revenues by $216 million and
        $157 million, respectively. That filing includes, among other things, a
        request to charge customers for an increasing amount of market priced power
        procured through a CBP as the amount of supply provided under the existing
        FES
        agreement is phased out in accordance with the April 7, 2006 Tolling
        Agreement described above. Met-Ed
        and Penelec
        also requested approval of the January 12, 2005 petition for the deferral
        of transmission-related costs discussed above, but only for those costs incurred
        during 2006. In this rate filing, Met-Ed and Penelec also requested recovery
        of
        annual transmission and related costs incurred on or after January 1, 2007,
        plus the amortized portion of 2006 costs over a ten-year period, along with
        applicable carrying charges, through an adjustable rider similar to that
        implemented in Ohio. Changes in the
        recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs
        are
        also included in the filing. The filing contemplates a reduction in distribution
        rates for Met-Ed of $37 million annually and an increase in distribution
        rates for Penelec of $20 million annually. The PPUC suspended the effective
        date (June 10, 2006) of these rate changes for seven months after the
        filing as permitted under Pennsylvania law. If the PPUC adopts the overall
        positions taken in the intervenors’ testimony as filed, this would have a
        material adverse effect on the financial statements of FirstEnergy, Met-Ed
        and
        Penelec. Hearings were held in late August 2006 and all reply briefs were
        filed
        by October 6, 2006. The ALJ’s recommended decision is due by November 8,
        2006 and the PPUC decision is expected by January 12, 2007.
  21
  
 As of September 30, 2006, Met-Ed's and Penelec's regulatory deferrals
        pursuant to the 1998 Restructuring Settlement (including the Phase 2
        Proceedings) and the FirstEnergy/GPU Merger Settlement Stipulation were
        $297 million and $56 million, respectively. Penelec's $56 million
        is subject to the pending resolution of taxable income issues associated
        with
        NUG trust fund proceeds. The PPUC recently conducted a review and audit of
        a
        modification to the NUG purchased power stranded cost accounting methodology
        for
        Met-Ed and Penelec. On August 18, 2006, a PPUC Order was entered requiring
        Met-Ed and Penelec to reflect the deferred NUG cost balances as if the stranded
        cost accounting methodology modification had not been implemented. As a result
        of the PPUC’s Order, Met-Ed recognized a pre-tax charge of approximately $10.3
        million in the third quarter of 2006, representing incremental costs deferred
        under the revised methodology in 2005. Met-Ed and Penelec continue to believe
        that the stranded cost accounting methodology modification is appropriate
        and
        filed a petition with the PPUC pursuant to its Order for authorization to
        reflect the stranded cost accounting methodology modification effective January
        1, 1999.
  On January 12, 2005, Met-Ed and Penelec filed, before the PPUC, a request
        for deferral of transmission-related costs beginning January 1, 2005. The
        OCA, OSBA, OTS, MEIUG, PICA, Allegheny Electric Cooperative and Pennsylvania
        Rural Electric Association all intervened in the case. Met-Ed and Penelec
        sought
        to consolidate this proceeding (and modified their request to provide deferral
        of 2006 transmission-related costs only) with the comprehensive rate filing
        they
        made on April 10, 2006 as described above. On May 4, 2006, the PPUC
        approved the modified request. Accordingly, Met-Ed and Penelec have deferred
        approximately $90 million and $21 million, respectively, representing
        transmission costs that were incurred from January 1, 2006 through
        September 30, 2006. On June 5, 2006, the OCA filed before the
        Commonwealth Court a petition for review of the PPUC’s approval of the deferral.
        On July 12, 2006, the Commonwealth Court granted the PPUC’s motion to quash the
        OCA’s appeal. The ratemaking treatment of the deferrals will be determined in
        the comprehensive rate filing proceeding discussed further above.
  Under Pennsylvania's electric competition law, Penn is required to secure
        generation supply for customers who do not choose alternative suppliers for
        their electricity. On October 11, 2005, Penn filed a plan with the PPUC to
        secure electricity supply for its customers at set rates following the end
        of
        its transition period on December 31, 2006. Penn recommended that the RFP
        process cover the period January 1, 2007 through May 31, 2008.
        Hearings before the PPUC were held on January 10, 2006 with main briefs
        filed on January 27, 2006 and reply briefs filed on February 3, 2006.
        On February 16, 2006, the ALJ issued a Recommended Decision to adopt Penn's
        RFP process with modifications. On April 20, 2006, the PPUC approved the
        Recommended Decision with additional modifications to use an RFP process
        with
        two separate solicitations. An initial solicitation was held for Penn in
        May
        2006 with all tranches fully subscribed, which was approved by the PPUC on
        June 2, 2006. On July 18, 2006, the second PLR solicitation was held for
        Penn. The tranches for the Residential Group and Small Commercial Group were
        fully subscribed. However, supply was not acquired for two tranches for the
        Large Commercial Group. On July 20, 2006, the PPUC approved the submissions
        for
        the second bid. A contingency solicitation was held on August 15, 2006 for
        the two remaining Large Commercial Group tranches. The PPUC rejected the
        bids
        from the contingency solicitation and directed Penn’s independent auction
        manager to offer the two unfilled Large Commercial tranches to the companies
        which had won tranches in the prior solicitations. This resulted in the
        acquisition of a supplier for the two remaining tranches, which were filed
        and
        accepted by the PPUC in a secretarial letter that was entered on
        September 22, 2006. On August 24, 2006, Penn made a compliance filing.
        OCA and OSBA filed exceptions to the compliance filing. Penn filed reply
        exceptions on September 5, 2006. On September 21, 2006, Penn submitted
        a revised compliance filing to the PPUC for the Residential Group and Small
        Commercial Group as a result of an agreement between Penn, OCA and OSBA.
The PPUC
        approved
        proposed rates for the large commercial and industrial customers at the PPUC
        Public meeting on October 19, 2006, and found that the results of the
        competitive solicitation process were consistent with prevailing market
        prices.
  On May 25, 2006, Penn filed a Petition for Review of the PPUC’s Orders of
        April 28, 2006 and May 4, 2006, which together decided the issues
        associated with Penn’s proposed Interim PLR Supply Plan. Penn has asked the
        Commonwealth Court to review the PPUC’s decision to deny Penn’s recovery of
        certain PLR costs through a reconciliation mechanism and the PPUC’s decision to
        impose a geographic limitation on the sources of alternative energy credits.
        On
        June 7, 2006, the PaDEP filed a Petition for Review appealing the PPUC’s
        ruling on the method by which alternative energy credits may be acquired
        and
        traded. Penn is unable to predict the outcome of this appeal.
 
 **NEW
        JERSEY**
 
 JCP&L is permitted to defer for future collection from customers the amounts
        by which its costs of supplying BGS to non-shopping customers and costs incurred
        under NUG agreements exceed amounts collected through BGS and NUGC rates
        and
        market sales of NUG energy and capacity. As of September 30, 2006, the
        accumulated deferred cost balance totaled approximately $340 million. New
        Jersey law allows for securitization of JCP&L's deferred balance upon
        application by JCP&L and a determination by the NJBPU that the conditions of
        the New Jersey restructuring legislation are met. On February 14, 2003,
        JCP&L filed for approval to securitize the July 31, 2003 deferred balance.
        On June 8, 2006, the NJBPU approved JCP&L’s request to issue securitization
        bonds associated with BGS stranded cost deferrals. On August 10, 2006,
        JCP&L Transition Funding II, a wholly owned subsidiary of JCP&L, issued
        $182 million of transition bonds with a weighted average interest rate of
        5.5%.
  22
  On
        December 2, 2005, JCP&L filed its request for recovery of
        $165 million of actual above-market NUG costs incurred from August 1,
        2003 through October 31, 2005 and forecasted above-market NUG costs for
        November and December 2005. On February 23, 2006, JCP&L filed updated data
        reflecting actual amounts through December 31, 2005 of $154 million of
        costs incurred since July 31, 2003. On March 29, 2006, a pre-hearing
        conference was held with the presiding ALJ. On July 18, 2006, JCP&L
        filed rebuttal testimony that included a request for an additional
        $14 million of costs that had been eliminated from the securitized amount.
Evidentiary hearings were held during September 2006 and the briefing schedule
        has been postponed pending settlement discussions.
 An NJBPU Decision and Order approving a Phase II Stipulation of Settlement
        and
        resolving the Motion for Reconsideration of the Phase I Order was issued
        on May
        31, 2005. The Phase II Settlement includes a performance standard pilot program
        with potential penalties of up to 0.25% of allowable equity return. The Order
        requires that JCP&L file quarterly reliability reports (CAIDI and SAIFI
        information related to the performance pilot program) through December 2006
        and
        updates to reliability related project expenditures until all projects are
        completed. The latest quarterly reliability reports were submitted on
        September 12, 2006. As of September 30, 2006, there were no
        performance penalties issued by the NJBPU.
 Reacting to the higher closing prices of the 2006 BGS fixed rate auction,
        the
        NJBPU, on March 16, 2006, initiated a generic proceeding to evaluate the
        auction process and potential options for the future. On April 6, 2006,
        initial comments were submitted. A public meeting was held on April 21, 2006
        and
        a legislative-type hearing was held on April 28, 2006. On June 21, 2006,
        the NJBPU approved the continued use of a descending block auction for the
        Fixed
        Price Residential Class. JCP&L filed its 2007 BGS company specific addendum
        on July 10, 2006. On October 27, 2006, the NJBPU approved the auction
        format to procure the 2007 Commercial Industrial Energy Price as well as
        the
        specific rules for both the Fixed Price and Commercial Industrial Energy
        Price
        auctions. These rules were essentially unchanged from the prior
        auctions.
 
 In
        accordance with an
        April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004
        supporting a continuation of the current level and duration of the funding
        of
        TMI-2 decommissioning costs by New Jersey customers without a reduction,
        termination or capping of the funding. On September 30, 2004, JCP&L
        filed an updated TMI-2 decommissioning study. This study resulted in an updated
        total decommissioning cost estimate of $729 million (in 2003 dollars)
        compared to the estimated $528 million (in 2003 dollars) from the prior 1995
        decommissioning study. The DRA filed comments on February 28, 2005
        requesting that decommissioning funding be suspended. On March 18, 2005,
        JCP&L filed a response to the Ratepayer Advocate’s comments. A schedule for
        further NJBPU proceedings has not yet been set.
 
 On
          August 1,
          2005, the NJBPU established a proceeding to determine whether additional
          ratepayer protections are required at the state level in light of the repeal
          of
          PUHCA pursuant to the EPACT. An NJBPU proposed rulemaking to address the
          issues
          was published in the NJ Register on December 19, 2005. The proposal would
          prevent a holding company that owns a gas or electric public utility from
          investing more than 25% of the combined assets of its utility and
          utility-related subsidiaries into businesses unrelated to the utility industry.
          A public hearing was held on February 7, 2006 and comments were submitted
          to the NJBPU. On August 16, 2006, the NJBPU approved the regulations with
          an effective date of October 2, 2006. These regulations are not expected
          to
          materially impact FirstEnergy or JCP&L. Also, in the same proceeding, the
          NJBPU Staff issued an additional draft proposal on March 31, 2006 addressing
          various issues including access to books and records, ring-fencing, cross
          subsidization, corporate governance and related matters. With the approval
          of
          the NJBPU Staff, the affected utilities jointly submitted an alternative
          proposal on June 1, 2006. Comments on the alternative proposal were submitted
          on
          June 15, 2006.
  On December 21, 2005, the NJBPU initiated a generic proceeding and requested
        comments in order to formulate an appropriate regulatory treatment for
        investment tax credits related to generation assets divested by New Jersey’s
        four electric utility companies. Comments were filed by the utilities and
        by the
        DRA. JCP&L filed a request with the IRS for a ruling on the issue. JCP&L
        was advised by the IRS on April 10, 2006 that the ruling was tentatively
        adverse. On April 28, 2006, the NJBPU directed JCP&L to withdraw its
        request for a private letter ruling on this issue, which had been previously
        filed with the IRS as ordered by the NJBPU. On May 11, 2006, after a JCP&L
        Motion for Reconsideration was denied by the NJBPU, JCP&L filed to withdraw
        the request for a private letter ruling. On July 19, 2006, the IRS acknowledged
        that the JCP&L ruling request was withdrawn.
  23
  
 **FERC
        MATTERS**
 On November 1, 2004, ATSI filed with the FERC a request to defer approximately
        $54 million of costs to be incurred from 2004 through 2007 in connection
        with
        ATSI’s VMEP, which represents ATSI’s adoption of newly identified industry “best
        practices” for vegetation management. On March
        4, 2005,
        the FERC approved ATSI’s request to defer the VMEP costs (approximately $34
        million has been deferred as of September 30, 2006). On March 28, 2006, ATSI
        and
        MISO filed with the FERC a request to modify ATSI’s Attachment O formula rate to
        include revenue requirements associated with recovery of deferred VMEP costs
        over a five-year period. The requested effective date to begin recovery was
        June
        1, 2006. Various parties filed comments responsive to the March 28, 2006
        submission. The FERC conditionally approved the filing on May 22, 2006, subject
        to a compliance filing that ATSI made on June 13, 2006. A request for rehearing
        of the FERC’s May 22, 2006 Order was filed by a party, which ATSI answered. On
        July 14, 2006, the FERC accepted ATSI’s June 13, 2006 compliance filing.
        The estimated annual revenues to ATSI from the VMEP cost recovery is $12
        million
        for each of the five years beginning June 1, 2006. On October 25,
        2006, the FERC denied the request for rehearing.




On
        January 24, 2006,
        ATSI and MISO filed a request with the FERC to correct ATSI’s Attachment O
        formula rate to reverse revenue credits associated with termination of revenue
        streams from transitional rates stemming from FERC’s elimination of RTOR.
        Revenues formerly collected under these rates were included in, and served
        to
        reduce, ATSI’s zonal transmission rate under the Attachment O formula. Absent
        the requested correction, elimination of these revenue streams would not
        be
        fully reflected in ATSI’s formula rate until June 1, 2008. On March 16, 2006,
        the FERC approved the revenue credit correction without suspension, effective
        April 1, 2006. One party sought rehearing of the FERC's order. The request
        for
        rehearing of this order was denied on June 27, 2006. The FERC accepted MISO’s
        and ATSI’s revised tariff sheets for filing on June 7, 2006. The estimated
        annual revenue impact of the correction mechanism is approximately $40 million
        effective on June 1, 2006.
 
 On
        November 18,
        2004, the FERC issued an order eliminating the RTOR for transmission service
        between the MISO and PJM regions. The FERC also ordered the MISO, PJM and
        the
        transmission owners within MISO and PJM to submit compliance filings containing
        a SECA mechanism to recover lost RTOR revenues during a 16-month transition
        period from load serving entities. The FERC issued orders in 2005 setting
        the
        SECA for hearing. ATSI, JCP&L, Met-Ed, Penelec, and FES continue to be
        involved in the FERC hearings concerning the calculation and imposition of
        the
        SECA charges. The hearing was held in May 2006. Initial briefs were submitted
        on
        June 9, 2006, and reply briefs were filed on June 27, 2006. The Presiding
        Judge
        issued an Initial Decision on August 10, 2006, rejecting the compliance filings
        made by the RTOs and transmission owners, ruling on various issues and directing
        new compliance filings. This decision is subject to review and approval by
        the
        FERC. Briefs addressing the Initial Decision were filed on September 11,
        2006
        and October 20, 2006. A final order could be issued by the FERC by the end
        of
        2006.
 
 On
        January 31, 2005,
        certain PJM transmission owners made three filings with the FERC pursuant
        to a
        settlement agreement previously approved by the FERC. JCP&L, Met-Ed and
        Penelec were parties to that proceeding and joined in two of the filings.
        In the
        first filing, the settling transmission owners submitted a filing justifying
        continuation of their existing rate design within the PJM RTO. In the second
        filing, the settling transmission owners proposed a revised Schedule 12 to
        the
        PJM tariff designed to harmonize the rate treatment of new and existing
        transmission facilities. Interventions and protests were filed on February
        22,
        2005. In the third filing, Baltimore Gas and Electric Company and Pepco
        Holdings, Inc. requested a formula rate for transmission service provided
        within
        their respective zones. On May 31, 2005, the FERC issued an order on these
        cases. First, it set for hearing the existing rate design and indicated that
        it
        will issue a final order within six months. American Electric Power Company,
        Inc. filed in opposition proposing to create a "postage stamp" rate for high
        voltage transmission facilities across PJM. Second, the FERC approved the
        proposed Schedule 12 rate harmonization. Third, the FERC accepted the proposed
        formula rate, subject to refund and hearing procedures. On June 30, 2005,
        the
        settling PJM transmission owners filed a request for rehearing of the May
        31,
        2005 order. On March 20, 2006, a settlement was filed with FERC in the formula
        rate proceeding that generally accepts the companies' formula rate proposal.
        The
        FERC issued an order approving this settlement on April 19, 2006. Hearings
        in
        the PJM rate design case concluded in April 2006. On July 13, 2006, an Initial
        Decision was issued by the ALJ. The ALJ adopted the Trial Staff’s position that
        the cost of all PJM transmission facilities should be recovered through a
        postage stamp rate. ****** The
        ALJ recommended
        an April 1, 2006 effective date for this change in rate design. If the FERC
        accepts this recommendation, the transmission rate applicable to many load
        zones
        in PJM would increase. FirstEnergy believes that significant additional
        transmission revenues would have to be recovered from the JCP&L, Met-Ed and
        Penelec transmission zones within PJM. JCP&L, Met-Ed and Penelec as part of
        the Responsible Pricing Alliance, filed a brief addressing the Initial Decision
        on August 14, 2006 and September 5, 2006. The case will be reviewed by the
        FERC with a decision anticipated in the fourth quarter of 2006. ******
  24
  
 On
        November 1, 2005,
        FES filed two power sales agreements for approval with the FERC. One power
        sales
        agreement provided for FES to provide the PLR requirements of the Ohio Companies
        at a price equal to the retail generation rates approved by the PUCO for
        a
        period of three years beginning January 1, 2006. The Ohio Companies will
        be
        relieved of their obligation to obtain PLR power requirements from FES if
        the
        Ohio CBP results in a lower price for retail customers. A similar power sales
        agreement between FES and Penn permits Penn to obtain its PLR power requirements
        from FES at a fixed price equal to the retail generation price during 2006.


On
        December 29,
        2005, the FERC issued an order setting the two power sales agreements for
        hearing. The order criticized the Ohio CBP, and required FES to submit
        additional evidence in support of the reasonableness of the prices charged
        in
        the power sales agreements. A pre-hearing conference was held on January
        18,
        2006 to determine the hearing schedule in this case. Under the procedural
        schedule approved in this case, FES expected an initial decision to be issued
        in
        late January 2007. However, on July 14, 2006, the Chief Judge granted the
        joint
        motion of FES and the Trial Staff to appoint a settlement judge in this
        proceeding and the procedural schedule was suspended pending settlement
        discussions among the parties. A settlement conference was held on September
        5,
        2006. FES and the Ohio Companies, Penn, and the PUCO, along
        with other
        parties, reached an agreement to settle the case. The settlement was filed
        with
        the FERC on October 17, 2006, and was unopposed by the remaining parties,
        including the FERC Trial Staff. Initial comments to the settlement are due
        by
        November 6, 2006.
 The
          terms of the
          settlement provide for modification of both the Ohio and Penn power supply
          agreements with FES. Under the Ohio power supply agreement, separate rates
          are
          established for the Ohio Companies’ PLR requirements, special retail contracts
          requirements, wholesale contract requirements, and interruptible buy-through
          retail load requirements. For their PLR and special retail contract
          requirements, the Ohio Companies will pay FES no more than the lower of
          (i) the
          sum of the retail generation charge, the rate stabilization charge, the
          fuel
          recovery mechanism charge, and FES’ actual incremental fuel costs for such
          sales; or (ii) the wholesale price cap. Different wholesale price caps
          are
          imposed for PLR sales, special retail contracts, and wholesale contracts.
          The
          wholesale price for interruptible buy-through retail load requirements
          is
          limited to the actual spot price of power obtained by FES to provide this
          power.
          The Ohio Companies have recognized the estimated additional amount payable
          to
          FES for power supplied during the nine months ended September 30, 2006.
          The
          wholesale rate charged by FES under the Penn power supply agreement will
          be no
          greater than the generation component of charges for retail PLR load in
          Pennsylvania. The FERC is expected to act on this case by the end of the
          fourth
          quarter of 2006.


As
        a result of
        Penn’s PLR competitive solicitation process approved by the PPUC, FES was
        selected as the winning bidder for a number of the tranches for individual
        customer classes. The balance of the tranches will be supplied by unaffiliated
        power suppliers. On October 2, 2006, FES filed an application with FERC under
        Section 205 of the Federal Power Act for authorization to make these affiliate
        sales to Penn. Interventions or protests were due on this filing on October
        23,
        2006. Penn was the only party to file an intervention in this proceeding.
The FERC
        is expected
        to act on this filing on or before December 1, 2006.
 
 On
        October 19, 2006,
        the FERC issued two final rules in connection with the Public Utility Holding
        Company Act of 2005 (PUHCA 2005). The final rules impose certain accounting,
        reporting and record-retention requirements for applicable holding companies
        and
        service companies, which includes FirstEnergy and certain of its
        subsidiaries.
 
 **12.
        - NEW
        ACCOUNTING STANDARDS AND INTERPRETATIONS**
 
 *SAB
                  108 -
                  “Considering the Effects of Prior Year Misstatements when Quantifying
                  Misstatements in Current Year Financial
                  Statements”*
 
 In
        September 2006, the SEC issued SAB 108, which provides interpretive guidance
        on
        how registrants should quantify financial statement misstatements. There
        is
        currently diversity in practice, with the two commonly used methods to quantify
        misstatements being the “rollover” method (which primarily focuses on the income
        statement impact of misstatements) and the “iron curtain” method (which focuses
        on the balance sheet impact). SAB 108 requires registrants to use a dual
        approach whereby both of these methods are considered in evaluating the
        materiality of financial statement errors. Prior materiality assessments
        will
        need to be reconsidered using both the rollover and iron curtain methods.
        This
        guidance will be effective for FirstEnergy in the fourth quarter of 2006.
        FE does
        not expect this Statement to have a material impact on its financial
        statements.
  25
   *EITF
        06-5 -
“Accounting for Purchases of Life Insurance-Determining the Amount That Could
        Be
        Realized in Accordance with FASB Technical Bulletin No. 85-4, Accounting
        for
        Purchases of Life Insurance”*
 
 In September 2006, the EITF reached a consensus on Issue 06-5 concluding
        that a
        policyholder should consider any additional amounts included in the contractual
        terms of the policy in determining the amount that could be realized under
        the
        insurance contract. Contractual limitations should be considered when
        determining the realizable amounts. Amounts that are recoverable by the
        policyholder at the discretion of the insurance company should be excluded
        from
        the amount that could be realized. Recoverable amounts in periods beyond
        one
        year from the surrender of the policy should be discounted in accordance
        with
        APB Opinion No. 21, “Interest on Receivables and Payables.” Consensus was
        also reached that a policyholder should determine the amount that could be
        realized under the insurance contract assuming the surrender of an
        individual-life by individual-life policy (or certificate by certificate
        in a
        group policy). Any amount that would ultimately be realized by the policyholder
        upon the assumed surrender of the final policy (or final certificate) should
        be
        included in the amount that could be realized under the insurance contract.
        The
        EITF also concluded that a policyholder should not discount the cash surrender
        value component of the amount that could be realized when contractual
        restrictions on the ability to surrender a policy exist. However, if the
        contractual limitations prescribe that the cash surrender value component
        of the
        amount that could be realized is a fixed amount, then the amount that could
        be
        realized should be discounted in accordance with APB Opinion No. 21. This
        Issue is effective for fiscal years beginning after December 15, 2006.
        FirstEnergy does not expect this EITF to have a material impact on its financial
        statements.
 *SFAS
        157 - “Fair
        Value Measurements”*
 
 In September 2006, the FASB issued SFAS 157, that establishes how companies
        should measure fair value when they are required to use a fair value measure
        for
        recognition or disclosure purposes under GAAP. This Statement addresses the
        need
        for increased consistency and comparability in fair value measurements and
        for
        expanded disclosures about fair value measurements. The key changes to current
        practice are: (1) the definition of fair value which focuses on an exit price
        rather than entry price; (2) the methods used to measure fair value such
        as
        emphasis that fair value is a market-based measurement, not an entity-specific
        measurement, as well as the inclusion of an adjustment for risk, restrictions
        and credit standing; and (3) the expanded disclosures about fair value
        measurements.
 
 This Statement is effective for financial statements issued for fiscal years
        beginning after November 15, 2007, and interim periods within those years.
        FirstEnergy is currently evaluating the impact of this Statement on its
        financial statements.
 
 *SFAS
                  158 -
                  “Employers’ Accounting for Defined Benefit Pension and Other
                  Postretirement Plans-an amendment of FASB Statements No. 87, 88,
                  106, and
                  132(R)”*
 
 In September 2006, the FASB issued SFAS 158, which requires companies to
        recognize a net liability or asset to report the overfunded or underfunded
        status of their defined benefit pension and other postretirement benefit
        plans
        on their balance sheets and recognize changes in funded status in the year
        in
        which the changes occur through other comprehensive income. The funded status
        to
        be measured is the difference between plan assets at fair value and the benefit
        obligation. This Statement requires that gains and losses and prior service
        costs or credits, net of tax, that arise during the period be recognized
        as a
        component of other comprehensive income and not as components of net periodic
        benefit cost. Additional information should also be disclosed in the notes
        to
        the financial statements about certain effects on net periodic benefit cost
        for
        the next fiscal year that arise from delayed recognition of the gains or
        losses,
        prior service costs or credits, and transition asset or obligation. Upon
        the
        initial application of this Statement and subsequently, an employer should
        continue to apply the provisions in Statements 87, 88 and 106 in measuring
        plan
        assets and benefit obligations as of the date of its statement of financial
        position and in determining the amount of net periodic benefit cost. This
        Statement is effective for FirstEnergy as of December 31, 2006. Based upon
        the December 31, 2005 measurement date, the estimated balance sheet impacts
        of adopting this Statement are a reduction in total assets of $0.4 billion,
        an increase in liabilities of $0.6 billion and a decrease in equity of
        $1 billion, before
        recognition
        of any related regulatory assets that may be appropriate under the
        circumstances.
   26
 
 *FSP
        FIN 46(R)-6
        - “Determining the Variability to Be Considered in Applying FASB interpretation
        No. 46(R)”*
 
 In
        April 2006, the
        FASB issued FSP FIN 46(R)-6 that addresses how a reporting enterprise should
        determine the variability to be considered in applying FASB interpretation
        No.
        46 (revised December 2003). FirstEnergy adopted FIN 46(R) in the first quarter
        of 2004, consolidating VIE’s when FirstEnergy or one of its subsidiaries is
        determined to be the VIE’s primary beneficiary. The variability that is
        considered in applying interpretation 46(R) affects the determination of
        (a)
        whether the entity is a VIE; (b) which interests are variable interests in
        the
        entity; and (c) which party, if any, is the primary beneficiary of the VIE.
        This
        FSP states that the variability to be considered shall be based on an analysis
        of the design of the entity, involving two steps:
 
 Step
                  1:
              Analyze
                  the
                  nature of the risks in the entityStep
                  2:
              Determine
                  the
                  purpose(s) for which the entity was created and determine the variability
                  the entity is designed to create and pass along to its interest
                  holders.
 
 After
        determining
        the variability to consider, the reporting enterprise can determine which
        interests are designed to absorb that variability. The guidance in this FSP
        is
        applied prospectively to all entities (including newly created entities)
        with
        which that enterprise first becomes involved and to all entities previously
        required to be analyzed under interpretation 46(R) when a reconsideration
        event
        has occurred after July 1, 2006. FirstEnergy does not expect this Statement
        to have a material impact on its financial statements.
  *FIN
        48 -
“Accounting for Uncertainty in Income Taxes - an interpretation of FASB
        Statement No. 109.”*
 
 In
        June 2006, the
        FASB issued FIN 48 which clarifies the accounting for uncertainty in income
        taxes recognized in an enterprise’s financial statements in accordance with FASB
        Statement No. 109, “Accounting for Income Taxes.” This interpretation prescribes
        a recognition threshold and measurement attribute for the financial statement
        recognition and measurement of a tax position taken or expected to be taken
        on a
        tax return. This interpretation also provides guidance on derecognition,
        classification, interest, penalties, accounting in interim periods, disclosure
        and transition. The evaluation of a tax position in accordance with this
        interpretation will be a two-step process. The first step will determine
        if it
        is more likely than not that a tax position will be sustained upon examination
        and should therefore be recognized. The second step will measure a tax position
        that meets the more likely than not recognition threshold to determine the
        amount of benefit to recognize in the financial statements. This interpretation
        is effective for fiscal years beginning after December 15, 2006. FirstEnergy
        is
        currently evaluating the impact of this Statement.
 
 **13.
        -
        SEGMENT INFORMATION**
  FirstEnergy has two reportable segments: regulated services and power supply
        management services. The aggregate “Other” segments do not individually meet the
        criteria to be considered a reportable segment. The regulated services segment's
        operations include the regulated sale of electricity and distribution and
        transmission services by its eight utility subsidiaries in Ohio, Pennsylvania
        and New Jersey. The power supply management services segment primarily consists
        of the subsidiaries (FES, FGCO, NGC and FENOC) that sell electricity in
        deregulated markets and operate and now own the generation facilities of
        OE,
        CEI, TE and Penn resulting from the deregulation of the Companies' electric
        generation business. “Other” consists of telecommunications services, the
        recently sold MYR (a construction service company) and retail natural gas
        operations (see Note 4). The assets and revenues for the other business
        operations are below the quantifiable threshold for operating segments for
        separate disclosure as “reportable segments.”
  The regulated services segment designs, constructs, operates and maintains
        FirstEnergy's regulated transmission and distribution systems. Its revenues
        are
        primarily derived from electricity delivery and transition cost recovery.
        Assets
        of the regulated services segment as of September 30, 2005 included
        generating units that were leased or whose output had been sold to the power
        supply management services segment. The regulated services segment’s 2005
        internal revenues represented the rental revenues for the generating unit
        leases
        which ceased in the fourth quarter of 2005 as a result of the intra-system
        generation asset transfers (see Note 14).
   27
  The power supply management services segment supplies the electric power
        needs
        of FirstEnergy’s end-use customers through retail and wholesale arrangements,
        including regulated retail sales to meet all or a portion of the PLR
        requirements of FirstEnergy's Ohio and Pennsylvania companies and competitive
        retail sales to customers primarily in Ohio, Pennsylvania, Maryland and
        Michigan. This business segment owns and operates FirstEnergy's generating
        facilities and purchases electricity to meet sales obligations. The
        segment's net income is primarily derived from all electric generation sales
        revenues less the related costs of electricity generation, including purchased
        power and net transmission, congestion and ancillary costs charged by PJM
        and
        MISO to deliver energy to retail customers.
  Segment reporting for interim periods in 2005 was revised to conform to the
        current year business segment organization and operations and the
        reclassification of discontinued operations (see Note 4). Changes in the
        current
        year operations reporting reflected in the revised 2005 segment reporting
        primarily includes the transfer of retail transmission revenues and PJM/MISO
        transmission revenues and expenses associated with serving electricity load
        previously included in the regulated services segment to the power supply
        management services segment. In addition, as a result of the 2005 Ohio tax
        legislation reducing the effective state income tax rate, the calculated
        composite income tax rates used in the two reportable segments’ results for 2005
        and 2006 have been changed to 40% from the 41% previously reported in their
        2005
        segment results. The net amounts of the changes in the 2005 reportable segments'
        income taxes reclassifications have been correspondingly offset in the 2005
        "Reconciling Adjustments." FSG is being disclosed as a reportable segment
        due to
        its subsidiaries qualifying as held for sale. Interest expense on holding
        company debt and corporate support services revenues and expenses are included
        in "Reconciling Adjustments."
   28
   **Segment
                  Financial Information**
              
              
              
              **Power****Supply****Regulated**
              
              **Management**
              
              **Facilities**
              
              
              
              **Reconciling****Three
                  Months Ended**
              
              **Services**
              
              **Services**
              
              **Services**
              
              **Other**
              
              **Adjustments**
              
              **Consolidated*****(In
                  millions)*****September
                  30, 2006**External
                  revenues
              
              $
              1,290
              
              $
              2,066
              
              $
              47
              
              $
              14
              
              $
              (16
              )
              $
              3,401Internal
                  revenues
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Total
                  revenues
              
              
              1,290
              
              
              2,066
              
              
              47
              
              
              14
              
              
              (16
              )
              
              3,401Depreciation
                  and amortization
              
              
              280
              
              
              (44
              )
              
              -
              
              
              1
              
              
              6
              
              
              243Investment
                  Income
              
              
              67
              
              
              19
              
              
              -
              
              
              -
              
              
              (40
              )
              
              46Net
                  interest
                  charges
              
              
              102
              
              
              56
              
              
              -
              
              
              1
              
              
              21
              
              
              180Income
                  taxes
              
              
              200
              
              
              119
              
              
              -
              
              
              (15
              )
              
              (32
              )
              
              272Income
                  before
                  discontinued operations
              
              
              297
              
              
              180
              
              
              1
              
              
              27
              
              
              (51
              )
              
              454Discontinued
                  operations
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Net
                  income
              
              
              297
              
              
              180
              
              
              1
              
              
              27
              
              
              (51
              )
              
              454Total
                  assets
              
              
              24,181
              
              
              6,822
              
              
              30
              
              
              290
              
              
              839
              
              
              32,162Total
                  goodwill
              
              
              5,911
              
              
              24
              
              
              -
              
              
              -
              
              
              -
              
              
              5,935Property
                  additions
              
              
              123
              
              
              126
              
              
              -
              
              
              -
              
              
              3
              
              
              252**September
                  30, 2005**External
                  revenues
              
              $
              1,481
              
              $
              1,824
              
              $
              59
              
              $
              138
              
              $
              2
              
              $
              3,504Internal
                  revenues
              
              
              79
              
              
              -
              
              
              -
              
              
              -
              
              
              (79
              )
              
              -Total
                  revenues
              
              
              1,560
              
              
              1,824
              
              
              59
              
              
              138
              
              
              (77
              )
              
              3,504Depreciation
                  and amortization
              
              
              409
              
              
              (22
              )
              
              -
              
              
              1
              
              
              5
              
              
              393Investment
                  income
              
              
              83
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              83Net
                  interest
                  charges
              
              
              88
              
              
              11
              
              
              -
              
              
              1
              
              
              57
              
              
              157Income
                  taxes
              
              
              264
              
              
              (9
              )
              
              -
              
              
              3
              
              
              (21
              )
              
              237Income
                  before
                  discontinued operations
              
              
              395
              
              
              (13
              )
              
              -
              
              
              6
              
              
              (56
              )
              
              332Discontinued
                  operations
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Net
                  income
              
              
              395
              
              
              (13
              )
              
              -
              
              
              6
              
              
              (56
              )
              
              332Total
                  assets
              
              
              28,385
              
              
              1,741
              
              
              82
              
              
              522
              
              
              644
              
              
              31,374Total
                  goodwill
              
              
              5,938
              
              
              24
              
              
              -
              
              
              62
              
              
              -
              
              
              6,024Property
                  additions
              
              
              207
              
              
              79
              
              
              -
              
              
              1
              
              
              7
              
              
              294
 
 **Nine
                  Months Ended****September
                  30, 2006**External
                  revenues
              
              $
              3,417
              
              $
              5,364
              
              $
              150
              
              $
              149
              
              $
              (49
              )
              $
              9,031Internal
                  revenues
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Total
                  revenues
              
              
              3,417
              
              
              5,364
              
              
              150
              
              
              149
              
              
              (49
              )
              
              9,031Depreciation
                  and amortization
              
              
              765
              
              
              (54
              )
              
              -
              
              
              3
              
              
              17
              
              
              731Investment
                  Income
              
              
              204
              
              
              36
              
              
              -
              
              
              1
              
              
              (121
              )
              
              120Net
                  interest
                  charges
              
              
              291
              
              
              160
              
              
              -
              
              
              5
              
              
              57
              
              
              513Income
                  taxes
              
              
              499
              
              
              236
              
              
              2
              
              
              (21
              )
              
              (93
              )
              
              623Income
                  before
                  discontinued operations
              
              
              736
              
              
              355
              
              
              (11
              )
              
              37
              
              
              (138
              )
              
              979Discontinued
                  operations
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Net
                  income
              
              
              736
              
              
              355
              
              
              (11
              )
              
              37
              
              
              (138
              )
              
              979Total
                  assets
              
              
              24,181
              
              
              6,822
              
              
              30
              
              
              290
              
              
              839
              
              
              32,162Total
                  goodwill
              
              
              5,911
              
              
              24
              
              
              -
              
              
              -
              
              
              -
              
              
              5,935Property
                  additions
              
              
              492
              
              
              473
              
              
              -
              
              
              2
              
              
              23
              
              
              990**September
                  30, 2005**External
                  revenues
              
              $
              3,923
              
              $
              4,617
              
              $
              162
              
              $
              385
              
              $
              10
              
              $
              9,097Internal
                  revenues
              
              
              238
              
              
              -
              
              
              -
              
              
              -
              
              
              (238
              )
              
              -Total
                  revenues
              
              
              4,161
              
              
              4,617
              
              
              162
              
              
              385
              
              
              (228
              )
              
              9,097Depreciation
                  and amortization
              
              
              1,128
              
              
              (26
              )
              
              -
              
              
              2
              
              
              18
              
              
              1,122Investment
                  income
              
              
              171
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              171Net
                  interest
                  charges
              
              
              285
              
              
              29
              
              
              1
              
              
              4
              
              
              170
              
              
              489Income
                  taxes
              
              
              613
              
              
              (43
              )
              
              4
              
              
              13
              
              
              12
              
              
              599Income
                  before
                  discontinued operations
              
              
              920
              
              
              (64
              )
              
              (6
              )
              
              18
              
              
              (216
              )
              
              652Discontinued
                  operations
              
              
              -
              
              
              -
              
              
              13
              
              
              5
              
              
              -
              
              
              18Net
                  income
              
              
              920
              
              
              (64
              )
              
              7
              
              
              23
              
              
              (216
              )
              
              670Total
                  assets
              
              
              28,385
              
              
              1,741
              
              
              82
              
              
              522
              
              
              644
              
              
              31,374Total
                  goodwill
              
              
              5,938
              
              
              24
              
              
              -
              
              
              62
              
              
              -
              
              
              6,024Property
                  additions
              
              
              506
              
              
              226
              
              
              1
              
              
              5
              
              
              18
              
              
              756
  Reconciling adjustments to segment operating results from internal management
        reporting to consolidated external financial reporting primarily consist
        of
        interest expense related to holding company debt, corporate support services
        revenues and expenses, fuel marketing revenues (which are reflected as
        reductions to expenses for internal management reporting purposes) and
        elimination of intersegment transactions.
  29
  
 **14.
        -
        FIRSTENERGY INTRA-SYSTEM GENERATION ASSET TRANSFERS**
  On May 13, 2005, Penn, and on May 18, 2005, the Ohio Companies,
        entered into certain agreements implementing a series of intra-system generation
        asset transfers that were completed in the fourth quarter of 2005. The asset
        transfers resulted in the respective undivided ownership interests of the
        Ohio
        Companies and Penn in FirstEnergy’s nuclear and non-nuclear generation assets
        being owned by NGC and FGCO, respectively. The generating plant interests
        transferred do not include leasehold interests of CEI, TE and OE in certain
        of
        the plants that are currently subject to sale and leaseback arrangements
        with
        non-affiliates.
  On October 24, 2005, the Ohio Companies and Penn completed the intra-system
        transfer of non-nuclear generation assets to FGCO. Prior to the transfer,
        FGCO,
        as lessee under a Master Facility Lease with the Ohio Companies and Penn,
        leased, operated and maintained the non-nuclear generation assets that it
        now
        owns. The asset transfers were consummated pursuant to FGCO's purchase option
        under the Master Facility Lease.
  On December 16, 2005, the Ohio Companies and Penn completed the intra-system
        transfer of their respective ownership in the nuclear generation assets to
        NGC
        through, in the case of OE and Penn, an asset spin-off by way of dividend
        and,
        in the case of CEI and TE, a sale at net book value. FENOC continues to operate
        and maintain the nuclear generation assets.
  These transactions were pursuant to the Ohio Companies’ and Penn’s restructuring
        plans that were approved by the PUCO and the PPUC, respectively, under
        applicable Ohio and Pennsylvania electric utility restructuring legislation.
        Consistent with the restructuring plans, generation assets that had been
        owned
        by the Ohio Companies and Penn were required to be separated from the regulated
        delivery business of those companies through transfer to a separate corporate
        entity. The transactions essentially completed the divestitures contemplated
        by
        the restructuring plans by transferring the ownership interests to NGC and
        FGCO
        without impacting the operation of the plants.
  **15.
        -
        JCP&L RESTATEMENT**
 
 JCP&L's
        earnings
        for the three months and nine months ended September 30, 2005 have been
        restated to reflect the results of a tax audit by the State of New Jersey,
        in
        which JCP&L became aware that the New Jersey Transitional Energy Facilities
        Assessment (TEFA) is not an allowable deduction for state income tax purposes.
        JCP&L had incorrectly claimed a state income tax deduction for TEFA payments
        and as a result, income taxes and interest expense were understated by
        $0.7 million and $0.6 million, respectively, in the third quarter of
        2005 and understated by $1.6 million and $1.8 million, respectively,
        in the nine months ended September 30, 2005. The effects of these
        adjustments on JCP&L's Consolidated Statements of Income for the three
        months and nine months ended September 30, 2005 are as
        follows:
 
 **Three
                  Months**
              
              **Nine
                  Months****As
                  Previously**
              
              
              **As**
              
              **As
                  Previously**
              
              **As****Reported**
              
              
              **Restated**
              
              **Reported**
              
              **Restated*****(In
                  millions)***Operating
                  Revenues
              $
              900.3
              
              $
              900.3
              
              $
              2,024.7
              
              $
              2,024.7Operating
                  Expenses andTaxes
              
              809.2
              
              
              809.9
              
              
              1,825.1
              
              
              1,826.7Operating
                  Income
              
              91.1
              
              
              90.4
              
              
              199.6
              
              
              198.0Other
                  Income
              
              3.0
              
              
              3.0
              
              
              3.3
              
              
              3.3Net
                  Interest
                  Charges
              
              18.9
              
              
              19.5
              
              
              57.9
              
              
              59.7Net
                  Income
              $
              75.2
              
              $
              73.9
              
              $
              145.0
              
              $
              141.6Earnings
                  Applicableto
                  Common
                  Stock
              $
              75.0
              
              $
              73.8
              
              $
              144.6
              
              $
              141.3
 
 These
        adjustments
        were not material to FirstEnergy's consolidated financial statements, nor
        JCP&L's Consolidated Balance Sheets or Consolidated Statements of Cash
        Flows.




30




**FIRSTENERGY
                  CORP.****CONSOLIDATED
                  STATEMENTS OF INCOME****(Unaudited)****Three
                  Months Ended**
              
              **Nine
                  Months Ended****September
                  30,**
              
              **September
                  30,****2006**
              
              **2005**
              
              **2006**
              
              **2005*****(In
                  millions, except per share amounts)*****REVENUES:**Electric
                  utilities
              
              $
              2,996
              
              $
              2,853
              
              $
              7,677
              
              $
              7,403Unregulated
                  businesses
              
              
              405
              
              
              651
              
              
              1,354
              
              
              1,694Total
                  revenues
              
              
              3,401
              
              
              3,504
              
              
              9,031
              
              
              9,097**EXPENSES:**Fuel
                  and
                  purchased power
              
              
              1,317
              
              
              1,287
              
              
              3,306
              
              
              3,115Other
                  operating expenses
              
              
              794
              
              
              993
              
              
              2,446
              
              
              2,750Provision
                  for
                  depreciation
              
              
              153
              
              
              152
              
              
              445
              
              
              444Amortization
                  of regulatory assets
              
              
              243
              
              
              366
              
              
              665
              
              
              983Deferral
                  of
                  new regulatory assets
              
              
              (153
              )
              
              (125
              )
              
              (379
              )
              
              (305
              )General
                  taxes
              
              
              187
              
              
              188
              
              
              553
              
              
              541Total
                  expenses
              
              
              2,541
              
              
              2,861
              
              
              7,036
              
              
              7,528**OPERATING
                  INCOME**
              
              
              860
              
              
              643
              
              
              1,995
              
              
              1,569**OTHER
                  INCOME (EXPENSE):**Investment
                  income
              
              
              46
              
              
              83
              
              
              120
              
              
              171Interest
                  expense
              
              
              (185
              )
              
              (162
              )
              
              (528
              )
              
              (488
              )Capitalized
                  interest
              
              
              7
              
              
              8
              
              
              21
              
              
              12Subsidiaries’
                  preferred stock dividends
              
              
              (2
              )
              
              (3
              )
              
              (6
              )
              
              (13
              )Total
                  other
                  expense
              
              
              (134
              )
              
              (74
              )
              
              (393
              )
              
              (318
              )**INCOME
                  BEFORE INCOME TAXES AND****DISCONTINUED
                  OPERATIONS**
              
              
              726
              
              
              569
              
              
              1,602
              
              
              1,251**INCOME
                  TAXES**
              
              
              272
              
              
              237
              
              
              623
              
              
              599**INCOME
                  BEFORE DISCONTINUED OPERATIONS**
              
              
              454
              
              
              332
              
              
              979
              
              
              652Discontinued
                  operations (net of income tax benefitof
                  $9 million)
                  (Note 4)
              
              
              -
              
              
              -
              
              
              -
              
              
              18**NET
                  INCOME**
              
              $
              454
              
              $
              332
              
              $
              979
              
              $
              670**BASIC
                  EARNINGS PER SHARE OF COMMON STOCK:**Earnings
                  before discontinued operations (Note 2)
              
              $
              1.41
              
              $
              1.01
              
              $
              2.99
              
              $
              1.99Discontinued
                  operations (Note 4)
              
              
              -
              
              
              -
              
              
              -
              
              
              0.05Net
                  earnings
                  per basic share
              
              $
              1.41
              
              $
              1.01
              
              $
              2.99
              
              $
              2.04**WEIGHTED
                  AVERAGE NUMBER OF BASIC SHARES****OUTSTANDING**
              
              
              322
              
              
              328
              
              
              326
              
              
              328**DILUTED
                  EARNINGS PER SHARE OF COMMON STOCK:**Earnings
                  before discontinued operations (Note 2)
              
              $
              1.40
              
              $
              1.01
              
              $
              2.97
              
              $
              1.98Discontinued
                  operations (Note 4)
              
              
              -
              
              
              -
              
              
              -
              
              
              0.05Net
                  earnings
                  per diluted share
              
              $
              1.40
              
              $
              1.01
              
              $
              2.97
              
              $
              2.03**WEIGHTED
                  AVERAGE NUMBER OF DILUTED SHARES****OUTSTANDING**
              
              
              325
              
              
              330
              
              
              329
              
              
              330**DIVIDENDS
                  DECLARED PER SHARE OF COMMON STOCK**
              
              $
              0.45
              
              $
              0.43
              
              $
              1.35
              
              $
              1.255The
                  preceding
                  Notes to Consolidated Financial Statements as they relate to FirstEnergy
                  Corp. are an integral part of thesestatements.
   31
  **FIRSTENERGY
                    CORP.****CONSOLIDATED
                    STATEMENTS OF COMPREHENSIVE INCOME****(Unaudited)****Three
                    Months Ended**
                
                **Nine
                    Months Ended****September
                    30,**
                
                **September
                    30,****2006**
                
                **2005**
                
                **2006**
                
                **2005*****(In
                    millions)*****NET
                    INCOME**
                
                $
                454
                
                $
                332
                
                $
                979
                
                $
                670**OTHER
                    COMPREHENSIVE INCOME (LOSS):**Unrealized
                    gain (loss) on derivative hedges
                
                
                (28
                )
                
                18
                
                
                45
                
                
                19Unrealized
                    gain (loss) on available for sale securities
                
                
                26
                
                
                (13
                )
                
                39
                
                
                (37
                )Other
                    comprehensive income (loss)
                
                
                (2
                )
                
                5
                
                
                84
                
                
                (18
                )Income
                    tax
                    expense (benefit) related to othercomprehensive
                    income
                
                
                (1
                )
                
                (2
                )
                
                30
                
                
                (8
                )Other
                    comprehensive income (loss), net of tax
                
                
                (1
                )
                
                7
                
                
                54
                
                
                (10
                )**COMPREHENSIVE
                    INCOME**
                
                $
                453
                
                $
                339
                
                $
                1,033
                
                $
                660The
                    preceding
                    Notes to Consolidated Financial Statements as they relate to
                    FirstEnergy
                    Corp. are an integral part ofthese
                    statements.
   32
  **FIRSTENERGY
                      CORP.****CONSOLIDATED
                      BALANCE SHEETS****(Unaudited)****September
                      30,**
                  
                  **December
                      31,****2006**
                  
                  **2005*****(In
                      millions)*****ASSETS****CURRENT
                      ASSETS:**Cash
                      and cash
                      equivalents
                  
                  
                  $
                  41
                  
                  $
                  64Receivables
                      -Customers
                      (less accumulated provisions of $44 million and$38
                      million,
                      respectively, for uncollectible accounts)
                  
                  
                  
                  1,226
                  
                  
                  1,293Other
                      (less
                      accumulated provisions of $26 million and$27
                      million,
                      respectively, for uncollectible accounts)
                  
                  
                  
                  194
                  
                  
                  205Materials
                      and
                      supplies, at average cost
                  
                  
                  
                  585
                  
                  
                  518Prepayments
                      and other
                  
                  
                  
                  168
                  
                  
                  2372,214
                  
                  
                  2,317**PROPERTY,
                      PLANT AND EQUIPMENT:**In
                      service
                  
                  
                  
                  23,823
                  
                  
                  22,893Less
                      -
                      Accumulated provision for depreciation
                  
                  
                  
                  9,986
                  
                  
                  9,79213,837
                  
                  
                  13,101Construction
                      work in progress
                  
                  
                  
                  673
                  
                  
                  89714,510
                  
                  
                  13,998**INVESTMENTS:**Nuclear
                      plant
                      decommissioning trusts
                  
                  
                  
                  1,874
                  
                  
                  1,752Investments
                      in
                      lease obligation bonds
                  
                  
                  
                  830
                  
                  
                  890Other
                  
                  
                  
                  770
                  
                  
                  7093,474
                  
                  
                  3,351**DEFERRED
                      CHARGES AND OTHER ASSETS:**Goodwill
                  
                  
                  
                  5,935
                  
                  
                  6,010Regulatory
                      assets
                  
                  
                  
                  4,434
                  
                  
                  4,486Prepaid
                      pension costs
                  
                  
                  
                  1,008
                  
                  
                  1,023Other
                  
                  
                  
                  587
                  
                  
                  65611,964
                  
                  
                  12,175$
                  32,162
                  
                  $
                  31,841**LIABILITIES
                      AND CAPITALIZATION****CURRENT
                      LIABILITIES:**Currently
                      payable long-term debt
                  
                  
                  $
                  1,667
                  
                  $
                  2,043Short-term
                      borrowings
                  
                  
                  
                  1,213
                  
                  
                  731Accounts
                      payable
                  
                  
                  
                  611
                  
                  
                  727Accrued
                      taxes
                  
                  
                  
                  752
                  
                  
                  800Other
                  
                  
                  
                  1,021
                  
                  
                  1,1525,264
                  
                  
                  5,453**CAPITALIZATION:**Common
                      stockholders’ equity -Common
                      stock,
                      $.10 par value, authorized 375,000,000 shares -319,205,517
                      and 329,836,276 shares outstanding, respectively
                  
                  
                  
                  32
                  
                  
                  33Other
                      paid-in
                      capital
                  
                  
                  
                  6,460
                  
                  
                  7,043Accumulated
                      other comprehensive income (loss)
                  
                  
                  
                  34
                  
                  
                  (20
                  )Retained
                      earnings
                  
                  
                  
                  2,695
                  
                  
                  2,159Unallocated
                      employee stock ownership plan common stock -718,671
                      and
                      1,444,796 shares, respectively
                  
                  
                  
                  (13
                  )
                  
                  (27
                  )Total
                      common
                      stockholders' equity
                  
                  
                  
                  9,208
                  
                  
                  9,188Preferred
                      stock of consolidated subsidiaries
                  
                  
                  
                  80
                  
                  
                  184Long-term
                      debt
                      and other long-term obligations
                  
                  
                  
                  8,760
                  
                  
                  8,15518,048
                  
                  
                  17,527**NONCURRENT
                      LIABILITIES:**Accumulated
                      deferred income taxes
                  
                  
                  
                  2,778
                  
                  
                  2,726Asset
                      retirement obligations
                  
                  
                  
                  1,179
                  
                  
                  1,126Power
                      purchase
                      contract loss liability
                  
                  
                  
                  1,205
                  
                  
                  1,226Retirement
                      benefits
                  
                  
                  
                  1,372
                  
                  
                  1,316Lease
                      market
                      valuation liability
                  
                  
                  
                  788
                  
                  
                  851Other
                  
                  
                  
                  1,528
                  
                  
                  1,6168,850
                  
                  
                  8,861**COMMITMENTS,
                      GUARANTEES AND CONTINGENCIES (Note 10)**$
                  32,162
                  
                  $
                  31,841The
                      preceding
                      Notes to Consolidated Financial Statements as they relate to
                      FirstEnergy
                      Corp. are an integral part of thesebalance
                      sheets.
   33
   **FIRSTENERGY
                  CORP.****CONSOLIDATED
                  STATEMENTS OF CASH FLOWS****(Unaudited)****Nine Months
                  Ended****September 30,****2006**
              
              **2005*****(In
                  millions)*****CASH
                  FLOWS FROM OPERATING ACTIVITIES:**Net
                  income
              $
              979
              
              $
              670Adjustments
                  to
                  reconcile net income to net cash from operating activities
                  -Provision
                  for
                  depreciation
              
              445
              
              
              444Amortization
                  of regulatory assets
              
              665
              
              
              983Deferral
                  of
                  new regulatory assets
              
              (379
              )
              
              (305
              )Nuclear
                  fuel
                  and lease amortization
              
              67
              
              
              63Deferred
                  purchased power and other costs
              
              (323
              )
              
              (258
              )Deferred
                  income taxes and investment tax credits, net
              
              36
              
              
              24Deferred
                  rents
                  and lease market valuation liability
              
              (54
              )
              
              (71
              )Accrued
                  compensation and retirement benefits
              
              78
              
              
              72Commodity
                  derivative transactions, net
              
              28
              
              
              (8
              )Gain
                  on asset
                  sales
              
              (38
              )
              
              -Income
                  from
                  discontinued operations
              
              -
              
              
              (18
              )Cash
                  collateral
              
              (98
              )
              
              49Decrease
                  (increase) in operating assets -Receivables
              
              (7
              )
              
              (226
              )Materials
                  and
                  supplies
              
              (30
              )
              
              (40
              )Prepayments
                  and other current assets
              
              (49
              )
              
              (57
              )Increase
                  (decrease) in operating liabilities -Accounts
                  payable
              
              (93
              )
              
              60Accrued
                  taxes
              
              (35
              )
              
              207Accrued
                  interest
              
              104
              
              
              92Electric
                  service prepayment programs
              
              (45
              )
              
              218Other
              
              (8
              )
              
              17Net
                  cash
                  provided from operating activities
              
              1,243
              
              
              1,916**CASH
                  FLOWS FROM FINANCING ACTIVITIES:**New
                  Financing
                  -Long-term
                  debt
              
              1,235
              
              
              334Short-term
                  borrowings, net
              
              482
              
              
              77Redemptions
                  and Repayments -Common
                  stock
              
              (600
              )
              
              -Preferred
                  stock
              
              (107
              )
              
              (170
              )Long-term
                  debt
              
              (993
              )
              
              (852
              )Net
                  controlled
                  disbursement activity
              
              (22
              )
              
              (27
              )Common
                  stock
                  dividend payments
              
              (439
              )
              
              (411
              )Net
                  cash used for financing activities
              
              (444
              )
              
              (1,049
              )**CASH
                  FLOWS FROM INVESTING ACTIVITIES:**Property
                  additions
              
              (990
              )
              
              (756
              )Proceeds
                  from
                  asset sales
              
              83
              
              
              61Proceeds
                  from
                  nuclear decommissioning trust fund sales
              
              1,325
              
              
              1,140Investments in
                  nuclear decommissioning trust funds
              
              (1,336
              )
              
              (1,216
              )Cash
                  investments
              
              109
              
              
              21Other
              
              (13
              )
              
              (30
              )Net
                  cash used
                  for investing activities
              
              (822
              )
              
              (780
              )Net
                  increase
                  (decrease) in cash and cash equivalents
              
              (23
              )
              
              87Cash
                  and cash
                  equivalents at beginning of period
              
              64
              
              
              53Cash
                  and cash
                  equivalents at end of period
              $
              41
              
              $
              140The
                  preceding
                  Notes to Consolidated Financial Statements as they relate to FirstEnergy
                  Corp. are an integral part of
                these
                  statements.
   34








***Report
      of Independent Registered Public Accounting Firm***





























Stockholders
      and
      Board of


Directors
      of
      FirstEnergy Corp.





We
      have reviewed the
      accompanying consolidated balance sheet of FirstEnergy Corp. and its
      subsidiaries as of September 30, 2006, and the related consolidated statements
      of income and comprehensive income for each of the three-month and nine-month
      periods ended September 30, 2006 and 2005 and the consolidated statements of
      cash flows for the nine-month periods ended September 30, 2006 and 2005. These
      interim financial statements are the responsibility of the Company’s
      management.





We
      conducted our
      review in accordance with the standards of the Public Company Accounting
      Oversight Board (United States). A review of interim financial information
      consists principally of applying analytical procedures and making inquiries
      of
      persons responsible for financial and accounting matters. It is substantially
      less in scope than an audit conducted in accordance with the standards of the
      Public Company Accounting Oversight Board, the objective of which is the
      expression of an opinion regarding the financial statements taken as a whole.
      Accordingly, we do not express such an opinion.





Based
      on our review,
      we are not aware of any material modifications that should be made to the
      accompanying consolidated interim financial statements for them to be in
      conformity with accounting principles generally accepted in the United States
      of
      America.





We
      have previously
      audited, in accordance with the standards of the Public Company Accounting
      Oversight Board (United States), the consolidated balance sheet as of December
      31, 2005, and the related consolidated statements of income, capitalization,
      common stockholders’ equity, preferred stock, cash flows and taxes for the year
      then ended, management’s assessment of the effectiveness of the Company’s
      internal control over financial reporting as of December 31, 2005 and the
      effectiveness of the Company’s internal control over financial reporting as of
      December 31, 2005; and in our report [which contained references to the
      Company’s change in its method of accounting for asset retirement obligations as
      of January 1, 2003 and conditional asset retirement obligations as of December
      31, 2005 as discussed in Note 2(K) and Note 12 to those consolidated financial
      statements and the Company’s change in its method of accounting for the
      consolidation of variable interest entities as of December 31, 2003 as discussed
      in Note 7 to those consolidated financial statements] dated February 27, 2006,
      we expressed unqualified opinions thereon. The consolidated financial statements
      and management’s assessment of the effectiveness of internal control over
      financial reporting referred to above are not presented herein. In our opinion,
      the information set forth in the accompanying consolidated balance sheet as
      of
      December 31, 2005, is fairly stated in all material respects in relation to
      the
      consolidated balance sheet from which it has been derived.





PricewaterhouseCoopers
                LLP
              Cleveland,
                Ohio
              October
                31,
                2006











35





**FIRSTENERGY
      CORP.**





**MANAGEMENT’S
      DISCUSSION AND ANALYSIS OF**


**RESULTS
      OF
      OPERATIONS AND FINANCIAL CONDITION**











**EXECUTIVE
      SUMMARY**




Net income in the third quarter of 2006 was $454 million, or basic earnings
      of $1.41 per share of common stock ($1.40 diluted), compared with net income
      of
      $332 million, or basic and diluted earnings of $1.01 per share of common
      stock in the third quarter of 2005. Net income in the first nine months of
      2006
      was $979 million, or basic earnings of $2.99 per share of common stock
      ($2.97 diluted) compared to $670 million in the first nine months of 2005,
      or basic earnings of $2.04 per share of common stock ($2.03 diluted). The
      increase in FirstEnergy’s earnings in both periods was driven primarily by
      reduced transition cost amortization for the Ohio Companies, cost deferrals
      authorized by the PUCO and PPUC, and reduced operating expenses. Earnings in
      the
      first nine months of 2006 also reflected increased electric sales revenues.
      Net
      income in the third quarter and first nine months of 2006 included unusual
      charges resulting from the PPUC’s NUG costs accounting order for prior year
      deferred costs of $10 million (or $6 million after-tax --$.02 per
      share) and the impact from the sale and impairment of non-core assets (or
      $1 million after-tax--$0.01 per share). Earnings in the first nine months
      of 2005 were reduced by $0.22 per share of common stock due to additional income
      tax expense of $71 million from the enactment of tax legislation in Ohio.
      The following Non-GAAP Reconciliation displays the unusual items resulting
      in
      the difference between GAAP and Non-GAAP earnings.





**Non-GAAP
                to GAAP Reconciliation**
            
            **2006**
            
            **2005****After-tax**
            
            **Basic**
            
            **After-tax**
            
            **Basic****Amount**
            
            **Earnings**
            
            **Amount**
            
            **Earnings****Three
                Months Ended September 30,**
            
            **(Millions)**
            
            **Per
                Share**
            
            **(Millions)**
            
            **Per
                Share**Earnings
                Before Unusual Items (Non-GAAP)
            
            $
            459
            
            $
            1.42
            
            $
            342
            
            $
            1.04Unusual
                Items:PPUC
                NUG
                adjustment applicable to prior years
            
            
            (6
            )
            
            (0.02
            )
            
            -
            
            
            -Non-core
                asset
                sales/impairments
            
            
            1
            
            
            0.01
            
            
            -
            
            
            -JCP&L
                arbitration decision
            
            
            -
            
            
            -
            
            
            (10
            )
            
            (0.03
            )Net
                Income
                (GAAP)
            
            $
            454
            
            $
            1.41
            
            $
            332
            
            $
            1.01**Nine
                Months Ended September 30,**Earnings
                Before Unusual Items (Non-GAAP)
            
            $
            995
            
            $
            3.04
            
            $
            730
            
            $
            2.22Unusual
                Items:PPUC
                NUG
                adjustment applicable to prior years
            
            
            (6
            )
            
            (0.02
            )
            
            -
            
            
            -Non-core
                asset
                sales/impairments
            
            
            (10
            )
            
            (0.03
            )
            
            22
            
            
            0.07Sammis
                plant
                New Source Review settlement
            
            
            -
            
            
            -
            
            
            (14
            )
            
            (0.04
            )Davis-Besse
                NRC fine
            
            
            -
            
            
            -
            
            
            (3
            )
            
            (0.01
            )New
                regulatory
                assets - JCP&L rate settlement
            
            
            
            
            
            
            
            
            16
            
            
            0.05JCP&L
                arbitration decision
            
            
            -
            
            
            -
            
            
            (10
            )
            
            (0.03
            )Ohio
                tax
                write-off
            
            
            -
            
            
            -
            
            
            (71
            )
            
            (0.22
            )Net
                Income
                (GAAP)
            
            $
            979
            
            $
            2.99
            
            $
            670
            
            $
            2.04








36





The
      Non-GAAP measure
      above, earnings before unusual items, is not calculated in accordance with
      GAAP
      because it excludes the impact of "unusual items." Unusual items reflect the
      impact on earnings of events that are not routine or for which FirstEnergy
      believes the financial impact will disappear or become immaterial within a
      near-term finite period. By removing the earnings effect of such issues that
      have been resolved or are expected to be resolved over the near-term, management
      and investors can better measure FirstEnergy’s business and earnings potential.
      In particular, the non-core asset sales impairments items refer to a finite
      set
      of energy-related assets that had been previously disclosed as held for sale,
      a
      substantial portion of which have already been sold. Similarly, the NRC fine
      in
      2005 and further litigation settlements similar to the New Source Review
      settlement in 2005 are not reasonably expected over the near-term. Furthermore,
      FirstEnergy believes presenting normalized earnings calculated in this manner
      provides useful information to investors in evaluating the ongoing results
      of
      FirstEnergy’s businesses over the longer term and assists investors in comparing
      FirstEnergy’s operating performance to the operating performance of others in
      the energy sector. Generally, a Non-GAAP financial measure is a numerical
      measure of a company’s historical or future financial performance, financial
      position, or cash flows that either excludes or includes amounts, or is subject
      to adjustment that has the effect of excluding or including amounts, that are
      not normally excluded or included in the most directly comparable measure
      calculated and presented in accordance with GAAP. Earnings per share before
      unusual items on a Non-GAAP basis (normalized earnings per share) are not
      calculated in accordance with GAAP because it excludes the impact of “unusual
      items.” Unusual items reflect the impact on earnings of material events that are
      not routine, including those that may be related to discontinued businesses
      or
      the cumulative effect of an accounting change. Management believes presenting
      normalized earnings calculated in this manner provides useful information to
      investors in evaluating the ongoing results of FirstEnergy’s businesses and
      assists investors in comparing FirstEnergy’s operating performance to the
      operating performance of other companies in the energy sector. FirstEnergy’s
      management frequently references Non-GAAP financial measures in its
      decision-making, using them to facilitate historical and ongoing performance
      comparisons as well as comparisons to the performance of peer companies.
      Non-GAAP measures should be considered in addition to, and not as a substitute
      for, their most directly comparable financial measures prepared in accordance
      with GAAP.





Total
      electric
      generation sales were down 1.3% in the third quarter of 2006 compared to last
      year's third quarter. The decrease resulted from a 32.9% reduction in wholesale
      sales, which more than offset a 7.7% increase in retail sales. For the nine
      months ended September 30, 2006, electric generation sales increased 1.4%
      over the same period last year. The year-to-date increase was primarily due
      to
      the return of customers to the Ohio Companies from third-party suppliers that
      exited the northern Ohio marketplace. Electric distribution deliveries were
      down
      2.3% and 2.2% for the quarter and year-to-date periods ending September 30,
      2006, compared with the respective periods of 2005, reflecting milder weather
      conditions in 2006.





FirstEnergy's
      generating fleet produced a record 61.9 billion KWH during the first nine
      months of 2006 compared to 59.5 billion KWH in the same period of 2005.
      FirstEnergy's non-nuclear fleet produced a record 40.1 billion KWH, while
      its nuclear facilities produced 21.8 billion KWH.




Share Repurchase Program - On
      August 10,
      2006, FirstEnergy repurchased 10.6 million shares, or approximately 3.2%,
      of its outstanding common stock through an accelerated share repurchase program
      with an affiliate of J.P. Morgan Securities. The initial purchase price was
      $600 million, or $56.44 per share. The final purchase price will be
      adjusted to reflect the average of the daily volume-weighted prices of the
      shares over a period of up to seven months. The share repurchase was initially
      funded with short-term debt. The share repurchase was executed under a
      June 20, 2006 Board of Directors’ authorization to repurchase up to
      12 million shares of common stock.





Renewed and Upsized Credit Facility - On August 24, 2006, FirstEnergy and
      certain of its subsidiaries, including all of its operating utility
      subsidiaries, entered into a new five-year syndicated credit facility totaling
      $2.75 billion. The new facility replaces FirstEnergy’s previous
      $2 billion credit facility and provides an average annual savings of 10
      basis points on facility-related borrowing costs. Borrowings under the new
      credit facility were used to pay off the outstanding borrowings under the
      previous facility. FirstEnergy can request an increase in the total commitments
      available under the new facility up to a maximum of $3.25 billion.
      Commitments under the new facility are available until August 24, 2011,
      unless the lenders agree, at the request of the Borrowers, to two additional
      one-year extensions. Generally, borrowings under the facility must be repaid
      within 364 days. Available amounts for each Borrower are subject to a specified
      sub-limit, as well as applicable regulatory and other limitations.




Pennsylvania Rate Matters - Evidentiary hearings in the Met-Ed and Penelec
      rate
      transition plan filings were held from August 24 through August 30,
      2006. Parties to the proceedings filed their Main Briefs on September 22,
      2006 and Reply Briefs on October 6, 2006. Met-Ed and Penelec anticipate an
      ALJ recommended decision in these proceedings by November 8, 2006 and a
      PPUC decision by January 12, 2007. As part of the transition of customers’
generation service toward market-based supply, Met-Ed and Penelec secured
      approximately 950 MW of their PLR supply under a competitive RFP for the period
      December 1, 2006 through December 31, 2008. Recovery of the
      incremental costs under the RFP is one component of the transition plan
      cases.





37




Met-Ed and Penelec NUG Accounting Methodology - On August 18, 2006,
      following a review and audit of FirstEnergy’s modification to its NUG purchased
      power stranded cost accounting methodology, the PPUC issued an order requiring
      Met-Ed and Penelec to revert to the original accounting methodology under which
      NUG regulatory asset balances are reduced when market prices exceed NUG costs
      during the month. As a result of the order, FirstEnergy and Met-Ed recognized
      a
      pre-tax charge of $10 million in the third quarter of 2006, relating to
      incremental NUG costs deferred in 2005 under the revised
      methodology.




Penn RFP - On October 19, 2006, the PPUC certified the RFP results for all
      customer classes reflecting the successful completion of the RFP bidding
      process. The RFP was conducted to secure Penn’s PLR supply for the period
      January 1, 2007 through May 31, 2008 for those customers that do not
      choose alternative suppliers.




JCP&L NUG Proceeding - An evidentiary hearing was held on September 20,
      2006 and settlement conferences were held in October 2006 in the proceeding
      involving JCP&L’s request to recover $165 million of actual
      above-market NUG costs incurred from August 1, 2003 through
      December 31, 2005. If approved, this request would increase cash flow, but
      would have no impact on earnings. Main briefs were filed October 30, 2006
      and reply briefs are due by November 20, 2006. An order by the NJBPU is
      expected in 2007.




Beaver Valley Power Station Uprates - In August 2006, Beaver Valley Unit 1
      increased its net output capability from 821 MW to 846 MW. This three-percent
      increase in capability is the first phase of its overall eight-percent power
      uprate recently approved by the NRC. The uprate was made possible by
      improvements to plant equipment and systems completed during the Unit’s spring
      refueling outage. The remainder of the eight-percent power uprate is expected
      to
      be implemented by early 2007. Similar work is planned for Beaver Valley Unit
      2.
      During the Unit’s current refueling outage, which began October 2, 2006,
      several modifications will be completed to prepare Beaver Valley Unit 2 for
      its
      eight-percent increase in generating capacity. After Beaver Valley Unit 2
      returns to service, three percent of the uprate is expected to take effect.
      The
      balance of the eight-percent power output increase is anticipated to be
      implemented during the next refueling outage in 2008. Beaver Valley Unit 2
      is
      expected to return to service from its current refueling outage in early to
      mid-November 2006.





**FIRSTENERGY’S
      BUSINESS**




FirstEnergy is a public utility holding company headquartered in Akron, Ohio,
      that operates primarily through two core business segments (see Results of
      Operations).


·
              **Regulated
                  Services**transmits and
                  distributes electricity through FirstEnergy's eight utility operating
                  companies that collectively comprise the nation’s fifth largest
                  investor-owned electric system, serving 4.5 million customers within
                  36,100 square miles of Ohio, Pennsylvania and New Jersey. This
                  business
                  segment derives its revenue principally from the delivery of electricity
                  generated or purchased by the Power Supply Management Services
                  segment or,
                  in some cases, purchased from independent suppliers in the states
                  where
                  the utility subsidiaries operate.·
              **Power
                  Supply Management****Services**supplies the
                  electric power needs of end-use customers through retail and wholesale
                  arrangements, including regulated retail sales to meet all or a
                  portion of
                  the PLR requirements of FirstEnergy's Ohio and Pennsylvania utility
                  subsidiaries and competitive retail sales to customers primarily
                  in Ohio,
                  Pennsylvania, Maryland and Michigan. This business segment owns
                  and
                  operates FirstEnergy's generating facilities and purchases electricity
                  to
                  meet sales obligations. The segment's net income is primarily derived
                  from
                  electric generation sales revenues less the related costs of electricity
                  generation, including purchased power, and net transmission, congestion
                  and ancillary costs charged by PJM and MISO to deliver energy to
                  retail
                  customers.




Other operating segments provide related services, including heating,
      ventilation, air-conditioning, refrigeration, electrical and facility control
      systems, high-efficiency electrotechnologies and telecommunication services.
      FirstEnergy is in the process of divesting its remaining non-core businesses
      (see Note 4). The assets and revenues for the other business operations are
      below the quantifiable threshold for separate disclosure as “reportable
      operating segments.”





**FIRSTENERGY
      INTRA-SYSTEM GENERATION ASSET TRANSFERS**




In 2005, the Ohio Companies and Penn entered into certain agreements
      implementing a series of intra-system generation asset transfers that were
      completed in the fourth quarter of 2005. The asset transfers resulted in the
      respective undivided ownership interests of the Ohio Companies and Penn in
      FirstEnergy’s nuclear and non-nuclear generation assets being owned by NGC and
      FGCO, respectively. The generating plant interests transferred do not include
      leasehold interests of CEI, TE and OE in certain of the plants that are
      currently subject to sale and leaseback arrangements with non-affiliates.





38




On October 24, 2005, the Ohio Companies and Penn completed the intra-system
      transfer of non-nuclear generation assets to FGCO. Prior to the transfer, FGCO,
      as lessee under a Master Facility Lease with the Ohio Companies and Penn,
      leased, operated and maintained the non-nuclear generation assets that it now
      owns. The asset transfers were consummated pursuant to FGCO's purchase option
      under the Master Facility Lease.




On December 16, 2005, the Ohio Companies and Penn completed the intra-system
      transfer of their respective ownership in the nuclear generation assets to
      NGC
      through, in the case of OE and Penn, an asset spin-off by way of dividend and,
      in the case of CEI and TE, a sale at net book value. FENOC continues to operate
      and maintain the nuclear generation assets.




These transactions were pursuant to the Ohio Companies’ and Penn’s restructuring
      plans that were approved by the PUCO and the PPUC, respectively, under
      applicable Ohio and Pennsylvania electric utility restructuring legislation.
      Consistent with the restructuring plans, generation assets that had been owned
      by the Ohio Companies and Penn were required to be separated from the regulated
      delivery business of those companies through transfer to a separate corporate
      entity. The transactions essentially completed the divestitures contemplated
      by
      the restructuring plans by transferring the ownership interests to NGC and
      FGCO
      without impacting the operation of the plants. The transfers were intercompany
      transactions and, therefore, had no impact on FirstEnergy’s consolidated
      results.





**RESULTS
      OF
      OPERATIONS**





The
      financial
      results discussed below include revenues and expenses from transactions among
      FirstEnergy's business segments. A reconciliation of segment financial results
      is provided in Note 13 to the consolidated financial statements. The FSG
      business segment is included in “Other and Reconciling Adjustments” in this
      discussion due to its


immaterial
      impact on
      current period financial results, but is presented separately in segment
      information provided in Note 13 to the consolidated financial statements.
      Net income (loss) by major business segment was as follows:





**Three
                Months Ended September 30,**
            
            **Nine
                Months Ended September 30,****Increase**
            
            
            
            **Increase****2006**
            
            **2005**
            
            **(Decrease)**
            
            **2006**
            
            **2005**
            
            **(Decrease)*****(In
                millions, except per share amounts)*****Net
                Income (Loss)****By
                Business Segment:**Regulated
                Services
            
            
            
            
            $
            297
            
            $
            395
            
            $
            (98
            )
            $
            736
            
            $
            920
            
            $
            (184
            )Power
                supply
                management services
            
            
            
            
            
            180
            
            
            (13
            )
            
            193
            
            
            355
            
            
            (64
            )
            
            419Other
                and
                reconciling adjustments*
            
            
            
            
            
            (23
            )
            
            (50
            )
            
            27
            
            
            (112
            )
            
            (186
            )
            
            74Total
            
            
            
            
            $
            454
            
            $
            332
            
            $
            122
            
            $
            979
            
            $
            670
            
            $
            309**Basic
                Earnings Per Share:**Earnings
                before discontinued operations
            
            
            
            
            $
            1.41
            
            $
            1.01
            
            $
            0.40
            
            $
            2.99
            
            $
            1.99
            
            $
            1.00Discontinued
                operations
            
            
            
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            0.05
            
            
            (0.05
            )Net
                earnings
                per basic share
            
            
            
            
            $
            1.41
            
            $
            1.01
            
            $
            0.40
            
            $
            2.99
            
            $
            2.04
            
            $
            0.95**Diluted
                Earnings Per Share:**Earnings
                before discontinued operations
            
            
            
            
            $
            1.40
            
            $
            1.01
            
            $
            0.39
            
            $
            2.97
            
            $
            1.98
            
            $
            0.99Discontinued
                operations
            
            
            
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            0.05
            
            
            (0.05
            )Net
                earnings
                per diluted share
            
            
            
            
            $
            1.40
            
            $
            1.01
            
            $
            0.39
            
            $
            2.97
            
            $
            2.03
            
            $
            0.94





*
            Represents
                other operating segments and reconciling items including interest
                expense
                on holding company debt and corporate support services revenues and
                expenses.





Net
      income in the
      third quarter and the first nine months of 2006 included a $10 million
      ($6 million after-tax) charge (or $0.02 per share) applicable to prior year
      NUG costs resulting from an August 2006 PPUC accounting order. Net income in
      the
      first nine months of 2006 was also reduced by the net charges associated with
      the sale and impairment of non-core assets of $10 million (or $0.03 per
      share).




Net income in the third quarter of 2005 included a $16 million
      ($10 million after-tax) charge (or $0.03 per share) resulting from a
      JCP&L arbitration decision. In the first nine months of 2005, net income was
      further reduced by additional income tax expense of $71 million (or $0.22
      per share) from the enactment of tax legislation in Ohio, $0.04 per share of
      expense associated with the W.H. Sammis Plant New Source Review settlement
      and
      $0.01 per share of expense related to the fine by the NRC regarding the
      Davis-Besse Nuclear Power Station. These reductions were partially offset by
      the
      combined impact of $0.07 per share of gains from the sale of non-core assets
      and
      a net benefit resulting from the JCP&L rate settlement of $16 million
      (or $0.05 per share).








39




***Summary
      of Results of
      Operations - Third Quarter of 2006 Compared with the Third Quarter of
      2005***





Financial
      results
      for FirstEnergy's major business segments in the third quarter of 2006 and
      2005
      were as follows:





**Power****Supply**
            
            **Other
                and****Regulated**
            
            **Management**
            
            **Reconciling**
            
            **FirstEnergy****3rd
                Quarter 2006 Financial Results**
            
            **Services**
            
            **Services**
            
            **Adjustments**
            
            **Consolidated*****(In
                millions)***Revenues:ExternalElectric
            
            $
            1,124
            
            $
            1,991
            
            $
            -
            
            $
            3,115Other
            
            
            166
            
            
            75
            
            
            45
            
            
            286Internal
            
            
            -
            
            
            -
            
            
            -
            
            
            -Total
                Revenues
            
            
            1,290
            
            
            2,066
            
            
            45
            
            
            3,401Expenses:Fuel
                and
                purchased power
            
            
            -
            
            
            1,317
            
            
            -
            
            
            1,317Other
                operating expenses
            
            
            338
            
            
            414
            
            
            42
            
            
            794Provision
                for
                depreciation
            
            
            96
            
            
            50
            
            
            7
            
            
            153Amortization
                of regulatory assets
            
            
            238
            
            
            5
            
            
            -
            
            
            243Deferral
                of
                new regulatory assets
            
            
            (54
            )
            
            (99
            )
            
            -
            
            
            (153
            )General
                taxes
            
            
            140
            
            
            43
            
            
            4
            
            
            187Total
                Expenses
            
            
            758
            
            
            1,730
            
            
            53
            
            
            2,541Operating
                Income (Loss)
            
            
            532
            
            
            336
            
            
            (8
            )
            
            860Other
                Income
                (Expense):Investment
                income
            
            
            67
            
            
            19
            
            
            (40
            )
            
            46Interest
                expense
            
            
            (104
            )
            
            (58
            )
            
            (23
            )
            
            (185
            )Capitalized
                interest
            
            
            4
            
            
            2
            
            
            1
            
            
            7Subsidiaries'
                preferred stock dividends
            
            
            (2
            )
            
            -
            
            
            -
            
            
            (2
            )Total
                Other
                Income (Expense)
            
            
            (35
            )
            
            (37
            )
            
            (62
            )
            
            (134
            )Income
                before
                income taxes
            
            
            497
            
            
            299
            
            
            (70
            )
            
            726Income
                tax
                expense (benefit)
            
            
            200
            
            
            119
            
            
            (47
            )
            
            272Net
                Income
                (Loss)
            
            $
            297
            
            $
            180
            
            $
            (23
            )
            $
            454





**Power****Supply**
            
            **Other
                and****Regulated**
            
            **Management**
            
            **Reconciling**
            
            **FirstEnergy****3rd
                Quarter 2005 Financial Results**
            
            **Services**
            
            **Services**
            
            **Adjustments**
            
            **Consolidated*****(In
                millions)***Revenues:ExternalElectric
            
            $
            1,340
            
            $
            1,777
            
            $
            -
            
            $
            3,117Other
            
            
            141
            
            
            47
            
            
            199
            
            
            387Internal
            
            
            79
            
            
            -
            
            
            (79
            )
            
            -Total
                Revenues
            
            
            1,560
            
            
            1,824
            
            
            120
            
            
            3,504Expenses:Fuel
                and
                purchased power
            
            
            -
            
            
            1,287
            
            
            -
            
            
            1,287Other
                operating expenses
            
            
            337
            
            
            537
            
            
            119
            
            
            993Provision
                for
                depreciation
            
            
            137
            
            
            9
            
            
            6
            
            
            152Amortization
                of regulatory assets
            
            
            366
            
            
            -
            
            
            -
            
            
            366Deferral
                of
                new regulatory assets
            
            
            (94
            )
            
            (31
            )
            
            -
            
            
            (125
            )General
                taxes
            
            
            150
            
            
            33
            
            
            5
            
            
            188Total
                Expenses
            
            
            896
            
            
            1,835
            
            
            130
            
            
            2,861Operating
                Income (Loss)
            
            
            664
            
            
            (11
            )
            
            (10
            )
            
            643Other
                Income
                (Expense):Investment
                income
            
            
            83
            
            
            -
            
            
            -
            
            
            83Interest
                expense
            
            
            (91
            )
            
            (12
            )
            
            (58
            )
            
            (161
            )Capitalized
                interest
            
            
            6
            
            
            1
            
            
            -
            
            
            7Subsidiaries'
                preferred stock dividends
            
            
            (3
            )
            
            -
            
            
            -
            
            
            (3
            )Total
                Other
                Income (Expense)
            
            
            (5
            )
            
            (11
            )
            
            (58
            )
            
            (74
            )Income
                before
                income taxes
            
            
            659
            
            
            (22
            )
            
            (68
            )
            
            569Income
                tax
                expense (benefit)
            
            
            264
            
            
            (9
            )
            
            (18
            )
            
            237Net
                Income
                (Loss)
            
            $
            395
            
            $
            (13
            )
            $
            (50
            )
            $
            332





40








**Power****Change
                Between 3rd Quarter 2006 and**
            
            
            
            **Supply**
            
            **Other
                and****3rd
                Quarter 2005 Financial Results**
            
            **Regulated**
            
            **Management**
            
            **Reconciling**
            
            **FirstEnergy****Increase
                (Decrease)**
            
            **Services**
            
            **Services**
            
            **Adjustments**
            
            **Consolidated*****(In
                millions)***Revenues:ExternalElectric
            
            $
            (216
            )
            $
            214
            
            $
            -
            
            $
            (2
            )Other
            
            
            25
            
            
            28
            
            
            (154
            )
            
            (101
            )Internal
            
            
            (79
            )
            
            -
            
            
            79
            
            
            -Total
                Revenues
            
            
            (270
            )
            
            242
            
            
            (75
            )
            
            (103
            )Expenses:Fuel
                and
                purchased power
            
            
            -
            
            
            30
            
            
            -
            
            
            30Other
                operating expenses
            
            
            1
            
            
            (123
            )
            
            (77
            )
            
            (199
            )Provision
                for
                depreciation
            
            
            (41
            )
            
            41
            
            
            1
            
            
            1Amortization
                of regulatory assets
            
            
            (128
            )
            
            5
            
            
            -
            
            
            (123
            )Deferral
                of
                new regulatory assets
            
            
            40
            
            
            (68
            )
            
            -
            
            
            (28
            )General
                taxes
            
            
            (10
            )
            
            10
            
            
            (1
            )
            
            (1
            )Total
                Expenses
            
            
            (138
            )
            
            (105
            )
            
            (77
            )
            
            (320
            )Operating
                Income
            
            
            (132
            )
            
            347
            
            
            2
            
            
            217Other
                Income
                (Expense):Investment
                income
            
            
            (16
            )
            
            19
            
            
            (40
            )
            
            (37
            )Interest
                expense
            
            
            (13
            )
            
            (46
            )
            
            35
            
            
            (24
            )Capitalized
                interest
            
            
            (2
            )
            
            1
            
            
            1
            
            
            -Subsidiaries'
                preferred stock dividends
            
            
            1
            
            
            -
            
            
            -
            
            
            1Total
                Other
                Income (Expense)
            
            
            (30
            )
            
            (26
            )
            
            (4
            )
            
            (60
            )Income
                before
                income taxes
            
            
            (162
            )
            
            321
            
            
            (2
            )
            
            157Income
                taxes
            
            
            (64
            )
            
            128
            
            
            (29
            )
            
            35Net
                Income
            
            $
            (98
            )
            $
            193
            
            $
            27
            
            $
            122





***Regulated
      Services - Third Quarter 2006 Compared to Third Quarter 2005***





Net
      income decreased
      $98 million (24.8%) to $297 million in the third quarter of 2006
      compared to $395 million in the third quarter of 2005, primarily due to
      decreased operating revenues partially offset by lower operating
      expenses.





*Revenues
      -*





The
      decrease in
      total revenues by service type is summarized below:





**Three
                Months Ended September 30,****Increase****Revenues
                By Type of Service**
            
            **2006**
            
            **2005**
            
            **(Decrease)*****(In
                millions)***Distribution
                services
            
            $
            1,124
            
            $
            1,340
            
            $
            (216
            )Transmission
                services
            
            
            109
            
            
            117
            
            
            (8
            )Internal
                lease
                revenues
            
            
            -
            
            
            79
            
            
            (79
            )Other
            
            
            57
            
            
            24
            
            
            33Total
                Revenues
            
            $
            1,290
            
            $
            1,560
            
            $
            (270
            )





Decreases
      in
      distribution deliveries by customer class are summarized in the following
      table:





**Electric
                Distribution Deliveries**Residential
            
            (4.9
            )%Commercial
            
            (1.0
            )%Industrial
            
            (0.6
            )%Total
                Distribution Deliveries
            
            (2.3
            )%








41





The
      completion of
      the Ohio Companies' generation transition cost recovery under their respective
      transition plans and Penn's transition plan in 2005 were the primary reasons
      for
      lower distribution unit prices, which, in conjunction with lower KWH deliveries,
      resulted in lower distribution delivery revenues. The decrease in deliveries
      to
      customers was primarily due to milder weather during the third quarter of 2006
      as compared to the same period in 2005. The following table summarizes major
      factors contributing to the $216 million decrease in distribution service
      revenues in the third quarter of 2006:





**Sources
                of Change in Distribution Revenues**
            
            **Increase**
              **(Decrease)*****(In
                millions)***Changes
                in
                customer usage
            
            $
            (70
            )Ohio
                shopping
                incentives
            
            
            77Reduced
                Ohio
                transition rates
            
            
            (244
            )Other
            
            
            21Net
                Decrease
                in Distribution Revenues
            
            $
            (216
            )





The
      decrease in
      internal lease revenues resulted from the generation asset transfers discussed
      above. The 2005 generation assets lease revenue from affiliates ceased as a
      result of the transfers.





*Expenses-*





The
      decrease in
      revenues discussed above was partially offset by the following decreases in
      total expenses:





·
            Lower
                depreciation expense of $41 million that resulted from the generation
                asset transfers;





·
            Reduced
                amortization of regulatory assets of $128 million principally due to
                the completion of Ohio generation transition cost recovery and Penn's
                transition plan in 2005; and





·
            Decreased
                general taxes of $10million
                primarily due to lower property taxes as a result of the generation
                asset
                transfers.





Those
      decreases in
      expenses were partially offset by the following:





·
            Other
                operating expenses were $1 million higher in 2006 due, in part, to
                the following factors:





-
            The
                absence in
                2006 of expenses for ancillary service refunds to third-parties of
                $9 million in 2005 due to the RCP, which provides that alternate
                suppliers of ancillary services now bill customers directly for those
                services;





-
            A
                $10 million decrease in employee and contractor costs resulting from
                reduced employee benefits (principally postretirement benefits) and
                the
                decreased use of outside contractors for tree trimming, reliability
                work,
                legal services and jobbing and contracting;
                and





-
            An
                $18 million increase due, in part, to regulatory fees, costs for
                jobbing and contracting and the absence in 2006 of an insurance
                settlement.





·
            The
                deferral
                of new regulatory assets was lower as a result of the end of shopping
                incentive deferrals under the Ohio Companies’ transition plan, partially
                offset by the distribution cost deferrals under the Ohio Companies’
                RCP.





*Other
      Income
      -*




Lower investment income reflects the impact of the generation asset transfers.
      The reduction in 2006 of the nuclear decommissioning trust income, the majority
      of which is now included in the power supply management services segment, was
      partially offset by interest income on the affiliated company notes receivable
      from the power supply management services segment in the third quarter of
      2006.




The $13 million increase in interest expense in the third quarter of 2006,
      compared with the same period of 2005, represents an additional $10 million
      of interest expense from OE’s June 2006 issuance of $600 million of
      unsecured senior notes. As discussed under Capital Resources and Liquidity,
      OE
      used the debt proceeds to repurchase $500 million of its common stock from
      FirstEnergy, who then redeemed $400 million of FirstEnergy notes in July
      2006. This represents a part of FirstEnergy’s 2006 refinancing strategy to
      obtain additional financing flexibility at the holding company (represented
      in
      the Other and Reconciling Adjustment segment) and to capitalize the regulated
      utilities more appropriately from a regulatory context.





42





***Power
      Supply Management Services - Third Quarter 2006 Compared to Third Quarter
      2005***





Net
      income for this
      segment was $180 million in the third quarter of 2006 compared to a net
      loss of $13 million in the same period last year. An improvement in the
      gross generation margin and increased transmission and fuel cost deferrals
      was
      partially offset by higher depreciation, general taxes and interest expense
      resulting from the generation asset transfers.





*Revenues
      -*




Electric generation sales revenues increased $185 million in the third
      quarter of 2006 compared to the same period in 2005. This increase primarily
      resulted from a 7.7% increase in retail KWH sales, mostly due to the return
      of
      customers as a result of third-party suppliers leaving the northern Ohio
      marketplace and higher unit prices resulting from the 2006 rate stabilization
      and fuel recovery charges. The higher retail sales reduced energy available
      for
      sale to the wholesale market. Increased transmission revenues resulted primarily
      from new revenues of approximately $34 million under the MISO transmission
      rider that began in the first quarter of 2006 and revenue increases from auction
      revenue rights and financial transmission rights.





An
      increase in
      reported segment revenues resulted from the following sources:





**Three
                Months Ended September 30,****Increase****Revenues
                By Type of Service**
            
            **2006**
            
            **2005**
            
            **(Decrease)*****(In
                millions)***Electric
                Generation Sales:Retail
            
            $
            1,640
            
            $
            1,254
            
            $
            386Wholesale
            
            
            229
            
            
            430
            
            
            (201
            )Total
                Electric
                Generation Sales
            
            
            1,869
            
            
            1,684
            
            
            185Transmission
            
            
            182
            
            
            110
            
            
            72Other
            
            
            15
            
            
            30
            
            
            (15
            )Total
                Revenues
            
            $
            2,066
            
            $
            1,824
            
            $
            242





The
      following table
      summarizes the price and volume factors contributing to changes in sales
      revenues from retail and wholesale customers:





**Increase****Source
                of Change in Electric Generation Sales**
            
            **(Decrease)*****(In
                millions)***Retail:Effect
                of 7.7%
                increase in customer usage
            
            $
            97Increased
                prices
            
            
            289386Wholesale:Effect
                of
                32.9% decrease in KWH sales
            
            
            (141
            )Lower
                prices
            
            
            (60
            )(201
            )Net
                Increase
                in Electric Generation Sales
            
            $
            185





*Expenses
      -*





Total
      operating
      expenses decreased by $105 million.
      The
      decrease was due to the following factors:





·
            Lower
                non-fuel
                operating expenses of $123 million reflect the absence in 2006 of
                generating lease rents ($79 million paid in 2005) due to the
                generation asset transfers and decreases in fossil production and
                transmission expenses of $20 million and $21 million,
                respectively, partially offset by higher nuclear operating expenses
                of
                $9 million. The lower fossil production expenses reflected higher
                credits of $24 million in 2006 from emission allowance sales compared
                to the same period of 2005. Decreased transmission expenses reflected
                lower congestion costs. Nuclear operating costs were higher principally
                due to preparation costs related to the Beaver Valley Unit 2 outage
                that
                began on October 2, 2006 and increased labor and benefit costs;
                and





43








·
            A
                $68 million increase in the deferral of new regulatory assets
                primarily related to the Ohio RCP fuel deferral of $43 million in
                2006. The increase also reflected PJM/MISO costs incurred that are
                expected to be recovered from customers through future rates. The
                recognition of these amounts under the Power Supply Management Services
                segment reflects a change in the current year operations reporting
                as
                discussed in Note 13 - Segment Information. Retail transmission revenues
                and PJM/MISO transmission revenues and expenses associated with serving
                electricity load are now included in the power supply management
                services
                segment results.





The
      above expense
      decreases were partially offset by the following:





·
            Higher
                fuel
                costs of $8 million, primarily coal cost increases resulting from
                higher coal commodity prices and increased transportation costs for
                western coal. The increased coal costs were partially offset by decreased
                generation output and lower natural gas and emission allowance costs
                of
                $20 million. Purchased power costs increased $22million
                due to
                higher prices and were partially offset by lower volumes. Factors
                producing the higher costs are summarized in the following table:





**Increase****Source
                of Change in Fuel and Purchased Power**
            
            **(Decrease)*****(In
                millions)***Fuel:Change
                due to
                increased unit costs
            
            $
            12Change
                due to
                volume consumed
            
            
            (4
            )8Purchased
                Power:Change
                due to
                increased unit costs
            
            
            68Change
                due to
                volume purchased
            
            
            (32
            )PPUC
                NUG
                adjustment applicable to prior year
            
            
            10Increase
                in
                NUG costs deferred
            
            
            (24
            )22Net
                Increase
                in Fuel and Purchased Power Costs
            
            $
            30








·
            Increased
                depreciation expenses of $41 million resulted principally from the
                generation asset transfers; and





·
            Higher
                general
                taxes of $10 million due to additional property taxes resulting from
                the generation asset transfers.





*Other
      Income and
      Expense -*





·
            Investment
                income in the third quarter of 2006 increased by $19 million over the
                prior year primarily due to nuclear decommissioning trust investments
                acquired  through the generation asset transfers;
                and·
            Interest
                expense increased by $46 million in the third quarter of 2006 primarily
                due to the interest expense on associated company notes payable that
                financed the generation asset transfers.





***Other
      -
      Third Quarter 2006 Compared to Third Quarter 2005*** ****





FirstEnergy’s
      financial results from other operating segments and reconciling items, including
      interest expense on holding company debt and corporate support services revenues
      and expenses, resulted in a $27 million increase to FirstEnergy’s net
      income in the third quarter of 2006 compared to the same quarter of 2005. The
      increase was primarily due to a $5 million improvement in gas commodity
      transactions, a $3 million increase in insurance investment income and
      $15 million of income tax benefits, primarily reflecting the 2005 federal
      income tax return filed in the third quarter of 2006.





44








***Summary
      of
      Results of Operations - First Nine Months of 2006 Compared with the First Nine
      Months of 2005***





Financial
      results
      for FirstEnergy's major business segments in the first nine months of 2006
      and
      2005 were as follows:





**Power****Supply**
            
            **Other
                and****Regulated**
            
            **Management**
            
            **Reconciling**
            
            **FirstEnergy****First
                Nine Months of 2006 Financial Results**
            
            **Services**
            
            **Services**
            
            **Adjustments**
            
            **Consolidated*****(In
                millions)***Revenues:ExternalElectric
            
            $
            2,972
            
            $
            5,207
            
            $
            -
            
            $
            8,179Other
            
            
            445
            
            
            157
            
            
            250
            
            
            852Internal
            
            
            -
            
            
            -
            
            
            -
            
            
            -Total
                Revenues
            
            
            3,417
            
            
            5,364
            
            
            250
            
            
            9,031Expenses:Fuel
                and
                purchased power
            
            
            -
            
            
            3,306
            
            
            -
            
            
            3,306Other
                operating expenses
            
            
            921
            
            
            1,270
            
            
            255
            
            
            2,446Provision
                for
                depreciation
            
            
            279
            
            
            146
            
            
            20
            
            
            445Amortization
                of regulatory assets
            
            
            650
            
            
            15
            
            
            -
            
            
            665Deferral
                of
                new regulatory assets
            
            
            (164
            )
            
            (215
            )
            
            -
            
            
            (379
            )General
                taxes
            
            
            409
            
            
            127
            
            
            17
            
            
            553Total
                Expenses
            
            
            2,095
            
            
            4,649
            
            
            292
            
            
            7,036Operating
                Income (Loss)
            
            
            1,322
            
            
            715
            
            
            (42
            )
            
            1,995Other
                Income
                (Expense):Investment
                income
            
            
            204
            
            
            36
            
            
            (120
            )
            
            120Interest
                expense
            
            
            (293
            )
            
            (168
            )
            
            (67
            )
            
            (528
            )Capitalized
                interest
            
            
            12
            
            
            8
            
            
            1
            
            
            21Subsidiaries'
                preferred stock dividends
            
            
            (10
            )
            
            -
            
            
            4
            
            
            (6
            )Total
                Other
                Income (Expense)
            
            
            (87
            )
            
            (124
            )
            
            (182
            )
            
            (393
            )Income
                before
                income taxes and discontinued operations
            
            
            1,235
            
            
            591
            
            
            (224
            )
            
            1,602Income
                tax
                expense (benefit)
            
            
            499
            
            
            236
            
            
            (112
            )
            
            623Income
                before
                discontinued operations
            
            
            736
            
            
            355
            
            
            (112
            )
            
            979Discontinued
                operations
            
            
            -
            
            
            -
            
            
            -
            
            
            -Net
                Income
                (Loss)
            
            $
            736
            
            $
            355
            
            $
            (112
            )
            $
            979





45








**Power****Supply**
            
            **Other
                and****Regulated**
            
            **Management**
            
            **Reconciling**
            
            **FirstEnergy****First
                Nine Months of 2005 Financial Results**
            
            **Services**
            
            **Services**
            
            **Adjustments**
            
            **Consolidated*****(In
                millions)***Revenues:ExternalElectric
            
            $
            3,509
            
            $
            4,523
            
            $
            -
            
            $
            8,032Other
            
            
            414
            
            
            94
            
            
            557
            
            
            1,065Internal
            
            
            238
            
            
            -
            
            
            (238
            )
            
            -Total
                Revenues
            
            
            4,161
            
            
            4,617
            
            
            319
            
            
            9,097Expenses:Fuel
                and
                purchased power
            
            
            -
            
            
            3,115
            
            
            -
            
            
            3,115Other
                operating expenses
            
            
            963
            
            
            1,505
            
            
            282
            
            
            2,750Provision
                for
                depreciation
            
            
            398
            
            
            26
            
            
            20
            
            
            444Amortization
                of regulatory assets
            
            
            983
            
            
            -
            
            
            -
            
            
            983Deferral
                of
                new regulatory assets
            
            
            (253
            )
            
            (52
            )
            
            -
            
            
            (305
            )General
                taxes
            
            
            423
            
            
            101
            
            
            17
            
            
            541Total
                Expenses
            
            
            2,514
            
            
            4,695
            
            
            319
            
            
            7,528Operating
                Income (Loss)
            
            
            1,647
            
            
            (78
            )
            
            -
            
            
            1,569Other
                Income
                (Expense):Investment
                income
            
            
            171
            
            
            -
            
            
            -
            
            
            171Interest
                expense
            
            
            (285
            )
            
            (28
            )
            
            (175
            )
            
            (488
            )Capitalized
                interest
            
            
            13
            
            
            (1
            )
            
            -
            
            
            12Subsidiaries'
                preferred stock dividends
            
            
            (13
            )
            
            -
            
            
            -
            
            
            (13
            )Total
                Other
                Income (Expense)
            
            
            (114
            )
            
            (29
            )
            
            (175
            )
            
            (318
            )Income
                before
                income taxes and discontinued operations
            
            
            1,533
            
            
            (107
            )
            
            (175
            )
            
            1,251Income
                tax
                expense (benefit)
            
            
            613
            
            
            (43
            )
            
            29
            
            
            599Income
                before
                discontinued operations
            
            
            920
            
            
            (64
            )
            
            (204
            )
            
            652Discontinued
                operations
            
            
            -
            
            
            -
            
            
            18
            
            
            18Net
                Income
                (Loss)
            
            $
            920
            
            $
            (64
            )
            $
            (186
            )
            $
            670





**Power****Change
                Between First Nine Months of 2006**
            
            
            
            **Supply**
            
            **Other
                and****and
                First Nine Months of 2005**
            
            **Regulated**
            
            **Management**
            
            **Reconciling**
            
            **FirstEnergy****Financial
                Results**-**Increase (Decrease)**
            
            **Services**
            
            **Services**
            
            **Adjustments**
            
            **Consolidated*****(In
                millions)***Revenues:ExternalElectric
            
            $
            (537
            )
            $
            684
            
            $
            -
            
            $
            147Other
            
            
            31
            
            
            63
            
            
            (307
            )
            
            (213
            )Internal
            
            
            (238
            )
            
            -
            
            
            238
            
            
            -Total
                Revenues
            
            
            (744
            )
            
            747
            
            
            (69
            )
            
            (66
            )Expenses:Fuel
                and
                purchased power
            
            
            -
            
            
            191
            
            
            -
            
            
            191Other
                operating expenses
            
            
            (42
            )
            
            (235
            )
            
            (27
            )
            
            (304
            )Provision
                for
                depreciation
            
            
            (119
            )
            
            120
            
            
            -
            
            
            1Amortization
                of regulatory assets
            
            
            (333
            )
            
            15
            
            
            -
            
            
            (318
            )Deferral
                of
                new regulatory assets
            
            
            89
            
            
            (163
            )
            
            -
            
            
            (74
            )General
                taxes
            
            
            (14
            )
            
            26
            
            
            -
            
            
            12Total
                Expenses
            
            
            (419
            )
            
            (46
            )
            
            (27
            )
            
            (492
            )Operating
                Income
            
            
            (325
            )
            
            793
            
            
            (42
            )
            
            426Other
                Income
                (Expense):Investment
                income
            
            
            33
            
            
            36
            
            
            (120
            )
            
            (51
            )Interest
                expense
            
            
            (8
            )
            
            (140
            )
            
            108
            
            
            (40
            )Capitalized
                interest
            
            
            (1
            )
            
            9
            
            
            1
            
            
            9Subsidiaries'
                preferred stock dividends
            
            
            3
            
            
            -
            
            
            4
            
            
            7Total
                Other
                Income (Expense)
            
            
            27
            
            
            (95
            )
            
            (7
            )
            
            (75
            )Income
                before
                income taxes and discontinued operations
            
            
            (298
            )
            
            698
            
            
            (49
            )
            
            351Income
                taxes
            
            
            (114
            )
            
            279
            
            
            (141
            )
            
            24Income
                before
                discontinued operations
            
            
            (184
            )
            
            419
            
            
            92
            
            
            327Discontinued
                operations
            
            
            -
            
            
            -
            
            
            (18
            )
            
            (18
            )Net
                Income
            
            $
            (184
            )
            $
            419
            
            $
            74
            
            $
            309





46





***Regulated
      Services - First Nine Months of 2006 Compared to First Nine Months of 2005***





Net
      income decreased
      $184 million (20.0%) to $736 million in the first nine months of 2006
      compared to $920 million in the first nine months of 2005, primarily due to
      decreased operating revenues partially offset by lower operating
      expenses.





*Revenues
      -*





The
      decrease in
      total revenues by service type is summarized below:





**Nine
                Months Ended September 30,****Increase****Revenues
                By Type of Service**
            
            **2006**
            
            **2005**
            
            **(Decrease)*****(In
                millions)***Distribution
                services
            
            $
            2,972
            
            $
            3,509
            
            $
            (537
            )Transmission
                services
            
            
            290
            
            
            314
            
            
            (24
            )Internal
                lease
                revenues
            
            
            -
            
            
            238
            
            
            (238
            )Other
            
            
            155
            
            
            100
            
            
            55Total
                Revenues
            
            $
            3,417
            
            $
            4,161
            
            $
            (744
            )





Decreases
      in
      distribution deliveries by customer class are summarized in the following
      table:





**Electric
                Distribution Deliveries**Residential
            
            
            (4.1
            )%Commercial
            
            
            (1.4
            )%Industrial
            
            
            (1.0
            )%Total
                Distribution Deliveries
            
            
            (2.2
            )%





The
      completion of
      the Ohio Companies' generation transition cost recovery under their respective
      transition plans and Penn's transition plan in 2005 were the primary reasons
      for
      lower distribution unit prices, which, in conjunction with lower KWH deliveries,
      resulted in lower distribution delivery revenues. The decreases in deliveries
      to
      customers were primarily due to milder weather during the first nine months
      of
      2006 as compared to the same period in 2005. The following table summarizes
      major factors contributing to the $537 million decrease in distribution
      service revenues in the first nine months of 2006:





**Sources
                of Change in Distribution Revenues**
            
            **Increase**
              **(Decrease)*****(In
                millions)***Changes
                in
                customer usage
            
            $
            (173
            )Ohio
                shopping
                incentives
            
            
            178Reduced
                Ohio
                transition rates
            
            
            (614
            )Other
            
            
            72Net
                Decrease
                in Distribution Revenues
            
            $
            (537
            )





The
      decrease in
      internal lease revenues reflected the effect of the generation asset transfers
      discussed above. The 2005 generation assets lease revenue from affiliates ceased
      as a result of the transfers. The increase in other revenues is due to higher
      payments received during the first quarter of 2006 under a contract provision
      associated with the prior sale of TMI, a 2006 uranium enrichment settlement
      and
      increased income on life insurance investments.





*Expenses-*





The
      decrease in
      revenues discussed above was partially offset by the following decreases in
      total expenses:





·
            Other
                operating expenses were $42 million lower in 2006 due, in part, to
                the following factors:





-
            The
                absence in
                2006 of expenses for ancillary service refunds to third parties of
                $22 million in 2005 due to the RCP, which provides that alternate
                suppliers of ancillary services now bill customers directly for those
                services;





47








-
            A
                $43 million decrease in employee and contractor costs resulting from
                lower storm-related expenses, reduced employee benefits and the decreased
                use of outside contractors for tree trimming, reliability work, legal
                services and jobbing and contracting;
                and





-
            A
                $22 million increase in other expenses due, in part, to the absence
                in 2006 of a $6 million insurance premium credit and a
                $3.4 million insurance settlement received in
                2005.





·
            Lower
                depreciation expense of $119 million resulted from the generation
                asset
                transfers;





·
            Reduced
                amortization of regulatory assets of $333 million resulted
                principally from the completion of Ohio generation transition cost
                recovery and Penn's transition plan in 2005;
                and





·
            General
                taxes
                decreased by $14 million primarily due to lower property taxes as a
                result of the generation asset
                transfers.





The
      reduction in the
      deferral of new regulatory assets resulted from last year’s JCP&L rate
      decision and the end of shopping incentive deferrals under the Ohio Companies’
transition plan, partially offset by the distribution cost deferrals under
      the
      Ohio Companies’ RCP.





*Other
      Income and
      Expense -*





·
            Higher
                investment income reflects the impact of the generation asset transfers.
                Interest income on the affiliated company notes receivable from the
                power
                supply management services segment in the first nine months of 2006
                is
                partially offset by the absence of nuclear decommissioning trust
                investments, the majority of which is now included in the power supply
                management services segment; and





·
            Interest
                expense increased by $8 million due to the June 2006 issuance of
                $600 million of OE long-term debt, which reflects FirstEnergy’s
                financing strategy as discussed in the third quarter results analysis.
                Subsidiaries' preferred stock dividends decreased by $3 million in
                2006
                due to redemption activity since the third quarter of
                2005.





***Power
      Supply Management Services - First Nine Months of 2006 Compared to First Nine
      Months of 2005***





Net
      income for this
      segment was $355 million in the first nine months of 2006 compared to a net
      loss of $64 million in the same period last year. An improvement in the
      gross generation margin and increased transmission and fuel costs deferrals
      was
      partially offset by higher depreciation, general taxes and interest expense
      resulting from the generation asset transfers.





*Revenues
      -*




Electric generation sales revenues increased $608 million in the first nine
      months of 2006 compared to the same period in 2005. This increase primarily
      resulted from a 7.4% increase in retail KWH sales, mostly due to the return
      of
      customers as a result of third-party suppliers leaving the northern Ohio
      marketplace and higher unit prices resulting from the 2006 rate stabilization
      and fuel recovery charges. The higher retail sales reduced energy available
      for
      sale to the wholesale market. Increased transmission revenues reflected new
      revenues of approximately $88 million under the MISO transmission rider
      that began in the first quarter of 2006. These increases were partially offset
      by a reduction in wholesale sales revenue as a result of both lower KWH sales
      and lower unit prices.





The
      increase in
      reported segment revenues resulted from the following sources:





**Nine
                Months Ended September 30,****Increase****Revenues
                By Type of Service**
            
            **2006**
            
            **2005**
            
            **(Decrease)*****(In
                millions)***Electric
                Generation Sales:Retail
            
            $
            4,164
            
            $
            3,223
            
            $
            941Wholesale
            
            
            717
            
            
            1,050
            
            
            (333
            )Total
                Electric
                Generation Sales
            
            
            4,881
            
            
            4,273
            
            
            608Transmission
            
            
            444
            
            
            292
            
            
            152Other
            
            
            39
            
            
            52
            
            
            (13
            )Total
                Revenues
            
            $
            5,364
            
            $
            4,617
            
            $
            747








48





The
      following table
      summarizes the price and volume factors contributing to changes in sales
      revenues from retail and wholesale customers:





**Increase****Source
                of Change in Electric Generation Sales**
            
            **(Decrease)*****(In
                millions)***Retail:Effect
                of 7.4%
                increase in customer usage
            
            $
            238Change
                in
                prices
            
            
            703941Wholesale:Effect
                of
                19.6% decrease in KWH sales
            
            
            (205
            )Change
                in
                prices
            
            
            (128
            )(333
            )Net
                Increase
                in Electric Generation Sales
            
            $
            608





*Expenses
      -*





Total
      operating
      expenses decreased by $46 million.
      The
      decrease was due to the following factors:





·  Lower
      non-fuel
      operating expenses of $235 million, which reflect the absence in 2006 of
      generating asset lease rents of $238 million charged in 2005 due to the
      generation asset transfers and the emission allowance sales credits discussed
      above in the third quarter results analysis. Also absent in 2006 were the 2005
      accrual of an $8.5 million civil penalty payable to the DOJ and $10 million
      for obligations to fund environmentally beneficial projects in connection with
      the Sammis Plant New Source Review settlement, and a $3.5 million penalty
      related to the Davis-Besse outage. These decreases were partially offset by
      increases in nuclear operating expenses of $9 million as discussed in the
      third quarter results analysis above and transmission expenses of
      $19 million; and





·  An
      increase of
      $163 million in the deferral of new regulatory assets, which consisted of
      PJM/MISO costs incurred that are expected to be recovered from customers through
      future rates and the Ohio RCP fuel deferral and related interest of
      $94 million.





The
      above decreases
      in expenses were partially offset by:





·
            Higher
                fuel
                and purchased power costs of $191 million, including increased fuel
                costs of $80 million. In particular, coal costs increased
                $107 million as a result of increased generation output, higher coal
                commodity prices and increased transportation costs for western coal.
                The
                increased coal costs were partially offset by lower natural gas and
                emission allowance costs of $36 million. Purchased power costs
                increased $111 million due to higher prices partially offset by lower
                volumes. Factors contributing to the higher costs are summarized
                in the
                following table:





**Increase****Source
                of Change in Fuel and Purchased Power**
            
            **(Decrease)*****(In
                millions)***Fuel:Change
                due to
                increased unit costs
            
            $
            46Change
                due to
                volume consumed
            
            
            3480Purchased
                Power:Change
                due to
                increased unit costs
            
            
            197Change
                due to
                volume purchased
            
            
            (62
            )PPUC
                NUG
                adjustment applicable to prior year
            
            
            10Increase
                in
                NUG costs deferred
            
            
            (34
            )111Net
                Increase
                in Fuel and Purchased Power Costs
            
            $
            191





·
            Increased
                depreciation expenses of $120 million, resulting principally from the
                generation asset transfers; and





·
            Higher
                general taxes of $26 million due to additional property taxes
                resulting from the generation asset transfers.







49








*Other
      Income and
      Expense -*





·
            Investment
                income in the first nine months of 2006 was $36 million higher
                primarily due to nuclear decommissioning trust investments acquired
                through the generation  asset transfers; and·
            Interest
                expense increased by $140 million, primarily due to interest on the
                associated company notes payable that financed the generation asset
                transfers. This increase was partially offset by an additional
                $9 million of capitalized
                interest.





***Other
      -
      First Nine Months of 2006 Compared to First Nine Months of
      2005***





FirstEnergy’s
      financial results from other operating segments and reconciling items, including
      interest expense on holding company debt and corporate support services revenues
      and expenses, resulted in a $74 million increase to FirstEnergy’s net
      income in the first nine months of 2006 compared to the same period of 2005.
      The
      increase was primarily due to the absence of last year’s write-off of income tax
      benefits of $71 million due to the 2005 change in Ohio tax legislation, the
      2006 income taxes benefits described in the Other - Third Quarter 2006 compared
      to Third Quarter 2005 results analysis above, a $3 million gain related to
      interest rate swap financing arrangements and a $6 million increase in
      insurance investment income in the first nine months of 2006. These increases
      were partially offset by the 2006 non-core assets sale and impairment charges
      of
      $10 million and the absence of the after-tax gains of $17 million from
      discontinued operations in 2005 (see Note 4). The following table summarizes
      the
      sources of income from discontinued operations (in millions) for the nine months
      ended September 30, 2005:





Discontinued
                Operations (Net of tax)Gain
                on
                sale:Natural
                gas
                business
            
            $
            5Elliot-Lewis,
                Spectrum and Power Piping
            
            
            12Reclassification
                of operating income
            
            
            1Total
            
            $
            18





**CAPITAL
      RESOURCES AND LIQUIDITY**




FirstEnergy expects to meet its future contractual obligations primarily with
      a
      combination of cash from operations and funds from the capital markets.
      Borrowing capacity under credit facilities is available to manage working
      capital requirements.





***Changes
      in Cash Position***




FirstEnergy's primary source of cash required for continuing operations as
      a
      holding company is cash from the operations of its subsidiaries. FirstEnergy
      also has access to $2.75 billion of short-term financing under a revolving
      credit facility which expires in 2011, subject to short-term debt limitations
      under current regulatory approvals of $1.5 billion and to outstanding
      borrowings by subsidiaries of FirstEnergy that are also parties to the facility.




In July 2006, FirstEnergy redeemed $400 million of its outstanding senior notes
      that were due to mature in November 2006 using cash proceeds from OE’s
      repurchase of $500 million of common stock.




I n
      August 2006, FirstEnergy repurchased 10.6 million shares, or approximately
      3.2%,
      of its outstanding common stock at an initial purchase price of $600 million,
      pursuant to an accelerated share repurchase program. The repurchase was funded
      with borrowings from FirstEnergy’s revolving credit facility.




As of September 30, 2006, FirstEnergy had $41 million of cash and cash
      equivalents compared with $64 million as of December 31, 2005. The
      major sources of changes in cash and cash equivalent balances are summarized
      below.





50





***Cash
      Flows From Operating Activities***





FirstEnergy's
      consolidated net cash from operating activities is provided primarily by its
      regulated services and power supply management services businesses (see Results
      of Operations above). Net cash provided from operating activities was
      $1.2 billion and $1.9 billion in the first nine months of 2006 and 2005,
      respectively, and is summarized as follows:





**Nine
                Months Ended****September
                30,****Operating
                Cash Flows**
            
            **2006**
            
            **2005*****(In
                millions)***Cash
                earnings
                *
            
            $
                1,472
            
            $
                1,572Working
                capital and other
            
            (229
            )
            344Net
                cash
                provided from operating activities
            
            $
                1,243
            
            $
                1,916*
                Cash
                earnings are a Non-GAAP measure (see reconciliation
                below).





Cash
      earnings (in
      the table above) are not a measure of performance calculated in accordance
      with
      GAAP. FirstEnergy believes that cash earnings is a useful financial measure
      because it provides investors and management with an additional means of
      evaluating its cash-based operating performance. Generally, a Non-GAAP financial
      measure is a numerical measure of a company’s historical or future financial
      performance, financial position, or cash flows that either excludes or includes
      amounts, or is subject to adjustment that has the effect of excluding or
      including amounts, that are not normally excluded or included in the most
      directly comparable measure calculated and presented in accordance with GAAP.
      Earnings before unusual items on a Non-GAAP basis (normalized earnings) are
      not
      calculated in accordance with GAAP because they exclude the impact of “unusual
      items.” Unusual items reflect the impact on earnings of material events that are
      not routine, including those that may be related to discontinued businesses
      or
      the cumulative effect of an accounting change. Management believes presenting
      normalized earnings calculated in this manner provides useful information to
      investors in evaluating the ongoing results of FirstEnergy’s businesses and
      assists investors in comparing the company’s operating performance to the
      operating performance of other companies in the energy sector. In addition,
      cash
      earnings (Non-GAAP) are not defined under GAAP. Management believes presenting
      this Non-GAAP measure provides useful information to investors in assessing
      FirstEnergy’s operating performance from a cash perspective without the effects
      of material unusual economic events. FirstEnergy’s management frequently
      references these Non-GAAP financial measures in its decision-making, using
      them
      to facilitate historical and ongoing performance comparisons as well as
      comparisons to the performance of peer companies. These Non-GAAP measures should
      be considered in addition to, and not as a substitute for, their most directly
      comparable financial measures prepared in accordance with GAAP.





**Nine
                Months Ended****September
                30,****Reconciliation
                of Cash Earnings**
            
            **2006**
            
            **2005*****(In
                millions)***Net
                income
                (GAAP)
            
            $
            979
            
            $
            670Non-cash
                charges (credits):Provision
                for
                depreciation
            
            
            445
            
            
            444Amortization
                of regulatory assets
            
            
            665
            
            
            983Deferral
                of
                new regulatory assets
            
            
            (379
            )
            
            (305
            )Nuclear
                fuel
                and lease amortization
            
            
            67
            
            
            63Deferred
                purchased power and other costs
            
            
            (323
            )
            
            (258
            )Deferred
                income taxes and investment tax credits
            
            
            36
            
            
            24Deferred
                rents
                and lease market valuation liability
            
            
            (54
            )
            
            (71
            )Accrued
                compensation and retirement benefits
            
            
            78
            
            
            72Gain
                on asset
                sales
            
            
            (38
            )
            
            -Income
                from
                discontinued operations
            
            
            -
            
            
            (18
            )Other
                non-cash
                expenses
            
            
            (4
            )
            
            (32
            )Cash
                earnings
                (Non-GAAP)
            
            $
            1,472
            
            $
            1,572








51








Net
      cash provided
      from operating activities decreased by $673 million in the first nine
      months of 2006 compared to the first nine months of 2005 primarily due to a
      $573 million decrease from working capital and a $100 million decrease
      in cash earnings described under "Results of Operations." The decrease from
      working capital changes primarily resulted from $242 million of funds
      received in 2005 for prepaid electric service (under a three-year Energy for
      Education Program with the Ohio Schools Council), increased outflows of
      $153 million for payables primarily caused by higher fuel and purchased
      power costs, increased tax payments of $242 million, and $147 million
      of cash collateral returned to suppliers. These decreases were partially offset
      by an increase in cash provided from the collection of receivables of $219
      million, reflecting increased electric sales revenues.





***Cash
      Flows From Financing Activities***





In
      the nine months
      ended September 30, 2006, cash used for financing activities was $444 million
      compared to $1.0 billion in the same period of 2005. The following table
      summarizes security issuances and redemptions.





**Nine
                Months Ended****September
                30,****Securities
                Issued or Redeemed**
            
            **2006**
            
            **2005*****(In
                millions)****New
                issues*Pollution
                control notes
            
            $
            253
            
            $
            334Secured
                notes
            
            
            382
            
            
            -Unsecured
                notes
            
            
            600
            
            
            -$
            1,235
            
            $
            334*Redemptions*First
                mortgage
                bonds
            
            $
            -
            
            $
            178Pollution
                control notes
            
            
            311
            
            
            377Secured
                notes
            
            
            182
            
            
            74Unsecured
                notes
            
            
            500
            
            
            8Long-term
                revolving credit
            
            
            -
            
            
            215Common
                stock
            
            
            600
            
            
            -Preferred
                stock
            
            
            107
            
            
            170$
            1,700
            
            $
            1,022Short-term
                borrowings, net
            
            $
            482
            
            $
            77





FirstEnergy
      had
      approximately $1.2 billion of short-term indebtedness as of September 30,
      2006 compared to approximately $731 million as of December 31, 2005.
      This increase primarily reflects FirstEnergy’s use of short-term debt to fund
      its $600 million common share repurchase in August 2006. Available bank
      borrowing capability (in millions) as of September 30, 2006 included the
      following:





**Borrowing
                Capability**Short-term
                credit facilities(1)
            
            $
            2,870Accounts
                receivable financing facilities
            
            
            550Utilized
            
            
            (1,207
            )LOCs
            
            
            (85
            )Net
            
            $
            2,128(1)A $2.75
                billion revolving credit facility that expires in 2011 is available
                in
                various amounts to FirstEnergy and certain of its subsidiaries, as
                described further below. A $100 million revolving credit facility
                that
                expires in December 2006 and a $20 million uncommitted line of credit
                facility are both available to FirstEnergy
                only.




As of September 30, 2006, the Ohio Companies and Penn had the aggregate
      capability to issue approximately $1.5 billion of additional FMB on the
      basis of property additions and retired bonds under the terms of their
      respective mortgage indentures. The issuance of FMB by OE and CEI are also
      subject to provisions of their senior note indentures generally limiting the
      incurrence of additional secured debt, subject to certain exceptions that would
      permit, among other things, the issuance of secured debt (including FMB) (i)
      supporting pollution control notes or similar obligations, or (ii) as an
      extension, renewal or replacement of previously outstanding secured debt. In
      addition, these provisions would permit OE and CEI to incur additional secured
      debt not otherwise permitted by a specified exception of up to $655 million
      and $579 million, respectively, as of September 30, 2006. Under the
      provisions of its senior note indenture, JCP&L may issue additional FMB only
      as collateral for senior notes. As of September 30, 2006, JCP&L had the
      capability to issue $626 million of additional senior notes upon the basis
      of FMB collateral.





52





Based upon applicable earnings coverage tests in their respective charters,
      Penn, TE and JCP&L could issue a total of $2.5 billion of preferred
      stock (assuming no additional debt was issued) as of September 30, 2006.
      CEI, Met-Ed and Penelec do not have similar restrictions and could issue up
      to
      the number of preferred shares authorized under their respective charters.
      As a
      result of OE redeeming all of its outstanding preferred stock in July 2006,
      the applicable earnings coverage test in its charter is inoperative. In the
      event that OE issues preferred stock in the future, the applicable earnings
      coverage test will govern the amount of preferred stock that OE may
      issue.




As of September 30, 2006, approximately $1.0 billion of capacity remained
      unused under an existing shelf registration statement, filed by FirstEnergy
      with
      the SEC in 2003, to support future securities issuances. The shelf registration
      provides the flexibility to issue and sell various types of securities,
      including common stock, debt securities, and share purchase contracts and
      related share purchase units. As of September 30, 2006, OE had
      approximately $400 million of capacity remaining unused under its existing
      shelf registration for unsecured debt securities. Shelf registration
      statements for unsecured debt securities for CEI of $550 million and TE of
      $300 million were declared effective by the SEC on October 31, 2006
      and remain unused.




On August 24, 2006, FirstEnergy and certain of its subsidiaries entered into
      a
      new $2.75 billion five-year revolving credit facility (included in the borrowing
      capability table above), which replaced FirstEnergy’s prior $2 billion credit
      facility. FirstEnergy
      may
      request an increase in the total commitments available under the new facility
      up
      to a maximum of $3.25 billion. Commitments under the new facility are
      available until August 24, 2011, unless the lenders agree, at the request
      of the Borrowers, to two additional one-year extensions. Generally, borrowings
      under the facility must be repaid within 364 days. Available amounts for each
      Borrower are subject to a specified sub-limit, as well as applicable regulatory
      and other limitations.





The following table summarizes the borrowing sub-limits for each borrower under
      the facility, as well as the limitations on short-term indebtedness applicable
      to each borrower under current regulatory approvals and applicable statutory
      and/or charter limitations:


**Revolving**
                
                **Regulatory
                    and****Credit
                    Facility**
                
                **Other
                    Short-Term****Borrower**
                
                **Sub-Limit**
                
                **Debt
                    Limitations****(1)*****(In
                    millions)*****FirstEnergy**
                
                $
                2,750
                
                $
                1,500**OE**
                
                
                500
                
                
                500**Penn**
                
                
                50
                
                
                44**CEI**
                
                
                250
                (3)
                
                600**TE**
                
                
                250
                (3)
                
                500**JCP&L**
                
                
                425
                
                
                429**Met-Ed**
                
                
                250
                
                
                250
                (2)**Penelec**
                
                
                250
                
                
                250
                (2)**FES**
                
                
                -
                (4)
                
                n/a**ATSI**
                
                
                -
                (4)
                
                50





(1)
            As
                of
                September 30, 2006.


(2)
            Excluding
                amounts which may be borrowed under the regulated money
                pool.


(3)
            Borrowing
                sub-limits for CEI and TE may be increased to up to $500 million by
                delivering notice to the administrative agent that such borrower
                has
                senior unsecured debt ratings of at least BBB by S&P and Baa2 by
                Moody’s.


(4)
            Borrowing
                sub-limits for FES and ATSI may be increased to up to $250 million
                and


$100 million,
      respectively, by delivering notice to the administrative agent that either
      (i)


such
      borrower has
      senior unsecured debt ratings of at least BBB- by S&P and Baa3 by


Moody’s
      or (ii)
      FirstEnergy has guaranteed the obligations of such borrower under the
      facility.





The
      revolving credit
      facility, combined with an aggregate $550 million ($390 million unused as
      of September 30, 2006) of accounts receivable financing facilities for OE,
      CEI, TE, Met-Ed, Penelec and Penn, are intended to provide liquidity to meet
      working capital and other general corporate requirements for FirstEnergy and
      its
      subsidiaries.





Under the revolving credit facility, borrowers may request the issuance of
      LOCs
      expiring up to one year from the date of issuance. The stated amount of
      outstanding LOCs will count against total commitments available under the
      facility and against the applicable borrower’s borrowing sub-limit. Total unused
      borrowing capability under existing credit facilities and accounts receivable
      financing facilities was $2.1 billion as of September 30,
      2006.





53





The revolving credit facility contains financial covenants requiring each
      borrower to maintain a consolidated debt to total capitalization ratio of no
      more than 65%, measured at the end of each fiscal quarter. As of
      September 30, 2006, FirstEnergy and its subsidiaries' debt to total
      capitalization ratios (as defined under the revolving credit facility) were
      as
      follows:





**Borrower****FirstEnergy**
            
            55
            %**OE**
            
            46
            %**Penn**
            
            33
            %**CEI**
            
            49
            %**TE**
            
            30
            %**JCP&L**
            
            23
            %**Met-Ed**
            
            38
            %**Penelec**
            
            35
            %





The
      revolving credit
      facility does not contain provisions that either restrict the ability to borrow
      or accelerate repayment of outstanding advances as a result of any change in
      credit ratings. Pricing is defined in “pricing grids”, whereby the cost of funds
      borrowed under the facility is related to the credit ratings of the company
      borrowing the funds.





FirstEnergy's
      regulated companies also have the ability to borrow from each other and the
      holding company to meet their short-term working capital requirements. A similar
      but separate arrangement exists among FirstEnergy's unregulated companies.
      FESC
      administers these two money pools and tracks surplus funds of FirstEnergy and
      the respective regulated and unregulated subsidiaries, as well as proceeds
      available from bank borrowings. Companies receiving a loan under the money
      pool
      agreements must repay the principal amount of the loan, together with
      accrued interest, within 364 days of borrowing the funds. The rate of interest is the
      same for each company receiving a loan from their respective pool and is based
      on the average cost of funds available through the pool. The average interest
      rate for borrowings in the first nine months of 2006 was approximately 5.09%
      for
      both the regulated companies’ money pool and the unregulated companies' money
      pool.




FirstEnergy’s access to capital markets and costs of financing are influenced by
      the ratings of its securities. The following table displays FirstEnergy’s and
      the Companies' securities ratings as of October 31, 2006. The ratings
      outlook from S&P on all securities is stable. The ratings outlook from
      Moody's and Fitch on all securities is positive.





**Issuer**
            
            **Securities**
            
            **S&P**
            
            **Moody’s**
            
            **Fitch****FirstEnergy**
            
            Senior
                unsecured
            
            BBB-
            
            Baa3
            
            BBB-**OE**
            
            Senior
                unsecured
            
            BBB-
            
            Baa2
            
            BBB**CEI**
            
            Senior
                secured
            
            BBB
            
            Baa2
            
            BBB-Senior
                unsecured
            
            BBB-
            
            Baa3
            
            BB+**TE**
            
            Senior
                secured
            
            BBB
            
            Baa2
            
            BBB-Preferred
                stock
            
            BB+
            
            Ba2
            
            BB**Penn**
            
            Senior
                secured
            
            BBB+
            
            Baa1
            
            BBB+Senior
                unsecured(1)
            
            BBB-
            
            Baa2
            
            BBBPreferred
                stock
            
            BB+
            
            Ba1
            
            BBB-**JCP&L**
            
            Senior
                secured
            
            BBB+
            
            Baa1
            
            BBB+**Met-Ed**
            
            Senior
                secured
            
            BBB+
            
            Baa1
            
            BBB+Senior
                unsecured
            
            BBB
            
            Baa2
            
            BBB**Penelec**
            
            Senior
                unsecured
            
            BBB
            
            Baa2
            
            BBB





(1)  Penn's
      only senior
      unsecured debt obligations are notes underlying pollution control revenue
      refunding bonds issued by the Ohio Air Quality Development Authority to which
      bonds this rating applies.





On
      January 20,
      2006, TE redeemed all 1.2 million of its outstanding shares of Adjustable
      Rate Series B preferred stock at $25.00 per share, plus accrued dividends to
      the
      date of redemption.





54





On
      April 3, 2006,
      $106.5 million of pollution control revenue refunding bonds were issued on
      behalf of NGC ($60 million at 3.07% and $46.5 million at 3.25%). The
      proceeds from the bonds were used to redeem the following Companies' pollution
      control notes: OE - $60 million at 7.05%, CEI - $27.7 million at 3.32%, TE
      - $18.8 million at 3.32%. Also, on April 3, 2006, $146.7 million of
      pollution control revenue refunding bonds were issued on behalf of FGCO ($90.1
      million at 3.03% and $56.6 million at 3.10%) which were used to redeem, in
      April
      and May 2006, the following Companies' pollution control notes: OE - $14.8
      million at 5.45%, Penn - $6.95 million at 5.45%, TE - $34.85 million
      at 3.18%, CEI - $47.5 million at 3.22%, $39.8 million at 3.20% and $2.8 million
      at 3.15%. These refinancings were undertaken in connection with FirstEnergy's
      intra-system generation asset transfers discussed above. The proceeds from
      NGC's
      and FGCO's refinancing issuances were used to repay a portion of their
      associated company notes payable to OE, Penn, CEI and TE, who then redeemed
      their respective pollution control notes.




On May 12, 2006, JCP&L issued $200 million of 6.40% secured senior
      notes due 2036. The proceeds of the offering were used to repay at maturity
      $150 million aggregate principal amount of JCP&L’s 6.45% senior notes
      due May 15, 2006 and for general corporate purposes.





On
      June 26,
      2006, OE issued $600 million of unsecured senior notes, comprised of $250
      million of 6.4% notes due 2016 and $350 million of 6.875% notes due 2036. The
      majority of the proceeds from this offering were used in July 2006 to repurchase
      $500 million of OE common stock from FirstEnergy, enabling FirstEnergy to
      accelerate repayment of $400 million of senior notes that were due to mature
      in
      November 2006. The remainder of the proceeds were used to redeem approximately
      $61 million of OE’s preferred stock on July 7, 2006 and to reduce
      short-term borrowings.





On
      August 10,
      2006, JCP&L Transition Funding II, a wholly owned subsidiary of JCP&L,
      issued $182 million of transition bonds with a weighted average interest rate
      of
      5.5% to
      securitize the recovery of deferred costs associated with JCP&L’s supply of
      BGS.




On August 10, 2006, FirstEnergy repurchased 10.6 million shares,
      approximately 3.2%, of its outstanding common stock through an accelerated
      share
      repurchase program. The initial purchase price was $600 million, or $56.44
      per share. The final purchase price will be adjusted to reflect the ultimate
      cost to acquire the shares over a period of up to seven months. The share
      repurchase was completed under a program authorized by the Board of Directors
      on
      June 20, 2006 to repurchase up to 12 million shares of common stock.
      At management’s discretion, additional shares may be acquired under the program
      on the open market or through privately negotiated transactions, subject to
      market conditions and other factors. The Board’s authorization of the repurchase
      program does not require FirstEnergy to make any further purchases of shares
      and
      the program may be terminated at any time.




FirstEnergy
      continues
      to pursue its strategy of replacing holding company debt with debt at its
      utility operating subsidiaries in order to obtain additional financing
      flexibility at the holding company level and capitalize its regulated utilities
      in a way that positions them appropriately in a regulatory context.





***Cash
      Flows From Investing Activities***





Net
      cash flows used
      in investing activities resulted principally from property additions. Regulated
      services expenditures for property additions primarily include expenditures
      supporting the transmission and distribution of electricity. Capital
      expenditures by the power supply management services segment are principally
      generation-related. The following table summarizes investments for the nine
      months ended September 30, 2006 and 2005 by segment:


**Summary
                      of Cash Flows**
                  
                  **Property****Used
                      for Investing Activities**
                  
                  **Additions**
                  
                  **Investments**
                  
                  **Other**
                  
                  **Total****Sources
                      (Uses)**
                  
                  ***(In
                      millions)*****Nine
                      Months Ended September 30, 2006**Regulated
                      services
                  
                  $
                  (492
                  )
                  $
                  142
                  
                  $
                  (8
                  )
                  $
                  (358
                  )Power
                      supply
                      management services
                  
                  
                  (473
                  )
                  
                  (7
                  )
                  
                  (1
                  )
                  
                  (481
                  )Other
                  
                  
                  (1
                  )
                  
                  (2
                  )
                  
                  -
                  
                  
                  (3
                  )Reconciling
                      items
                  
                  
                  (24
                  )
                  
                  24
                  
                  
                  20
                  
                  
                  20Total
                  
                  $
                  (990
                  )
                  $
                  157
                  
                  $
                  11
                  
                  $
                  (822
                  )**Nine
                      Months Ended September 30, 2005**Regulated
                      services
                  
                  $
                  (506
                  )
                  $
                  (14
                  )
                  $
                  (7
                  )
                  $
                  (527
                  )Power
                      supply
                      management services
                  
                  
                  (226
                  )
                  
                  15
                  
                  
                  -
                  
                  
                  (211
                  )Other
                  
                  
                  (6
                  )
                  
                  3
                  
                  
                  (17
                  )
                  
                  (20
                  )Reconciling
                      items
                  
                  
                  (18
                  )
                  
                  (9
                  )
                  
                  5
                  
                  
                  (22
                  )Total
                  
                  $
                  (756
                  )
                  $
                  (5
                  )
                  $
                  (19
                  )
                  $
                  (780
                  )






55





Net cash used for investing activities in the first nine months of 2006
      increased by $42 million compared to the first nine months of 2005. The
      increase was principally due to a $234 million increase in property
      additions which reflects the replacement of the steam generators and reactor
      head at Beaver Valley Unit 1, air quality control system expenditures and the
      distribution system Accelerated Reliability Improvement Program. The increase
      in
      property additions was partially offset by a $65 million decrease in net
      nuclear decommissioning trust activities due to the completion of the Ohio
      Companies' and Penn's transition cost recovery for decommissioning at the end
      of
      2005 and $88 million from cash investments, primarily from the expiration
      of restrictions on an escrow fund and mortgage indenture deposit.




During the last quarter of 2006, capital requirements for property additions
      and
      capital leases are expected to be approximately $324 million. FirstEnergy
      and the Companies have additional requirements of approximately
      $648 million for maturing long-term debt during the remainder of 2006.
      These cash requirements are expected to be satisfied from a combination of
      internal cash, funds raised in the long-term debt capital markets and short-term
      credit arrangements.




FirstEnergy's capital spending for the period 2006-2010 is expected to be
      approximately $6.8 billion (excluding nuclear fuel), of which
      $1.2 billion applies to 2006. Investments for additional nuclear fuel
      during the 2006-2010 periods are estimated to be approximately
      $885 million, of which approximately $166 million applies to 2006. During
      the same period, FirstEnergy's nuclear fuel investments are expected to be
      reduced by approximately $598 million and $91 million, respectively,
      as the nuclear fuel is consumed.





**GUARANTEES
      AND OTHER ASSURANCES**




As part of normal business activities, FirstEnergy enters into various
      agreements on behalf of its subsidiaries to provide financial or performance
      assurances to third parties. These agreements include contract guarantees,
      surety bonds, and LOCs. Some of the guaranteed contracts contain collateral
      provisions that are contingent upon FirstEnergy's credit ratings.




As of September 30, 2006, FirstEnergy's maximum exposure to potential
      future payments under outstanding guarantees and other assurances totaled
      approximately $3.6 billion, as summarized below:





**Maximum****Guarantees
                and Other Assurances**
            
            **Exposure*****(In
                millions)***FirstEnergy
                Guarantees of Subsidiaries:Energy
                and
                Energy-Related Contracts(1)
            
            $
            887Other(2)
            
            
            1,0941,981Surety
                Bonds
            
            
            147LOC(3)(4)
            
            
            1,434Total
                Guarantees and Other Assurances
            
            $
            3,562








(1)
            Issued
                for
                open-ended terms, with a 10-day termination right by
                FirstEnergy.


(2)
            Issued
                for
                various terms.


(3)
            Includes
                $85 million issued for various terms under LOC capacity available
                under FirstEnergy’s revolving credit agreement and $730 million
                outstanding in support of pollution control revenue bonds issued
                with
                various maturities.


(4)
            Includes
                approximately $194 million pledged in connection with the sale and
                leaseback of Beaver Valley Unit 2 by CEI and TE, $291 million pledged
                in connection with the sale and leaseback of Beaver Valley Unit 2
                by OE
                and $134 million pledged in connection with the sale and leaseback of
                the Perry Nuclear Power Plant by
                OE.





56




FirstEnergy
        guarantees energy and energy-related payments of its subsidiaries involved
        in
        energy commodity activities principally to facilitate normal physical
        transactions involving electricity, gas, emission allowances and coal.
        FirstEnergy also provides guarantees to various providers of credit support
        for
        subsidiary financings or refinancings of costs related to the acquisition
        of, or
        improvements to, property, plant and equipment. These agreements legally
        obligate FirstEnergy to fulfill the obligations of its subsidiaries directly
        involved in these energy and energy-related transactions or financings where
        the
        law might otherwise limit the counterparties' claims. If demands of a
        counterparty were to exceed the ability of a subsidiary to satisfy existing
        obligations, FirstEnergy's guarantee enables the counterparty's legal claim
        to
        be satisfied by FirstEnergy's other assets. The likelihood that such parental
        guarantees will increase amounts otherwise paid by FirstEnergy to meet its
        obligations incurred in connection with ongoing energy and energy-related
        contracts is remote.
 
 While these types of guarantees are normally parental commitments for the
        future
        payment of subsidiary obligations, subsequent to the occurrence of a credit
        rating downgrade or “material adverse event” the immediate posting of cash
        collateral or provision of an LOC may be required of the subsidiary. As of
        September 30, 2006, FirstEnergy's maximum exposure under these collateral
        provisions was $487 million.
 
 Most of FirstEnergy's surety bonds are backed by various indemnities common
        within the insurance industry. Surety bonds and related guarantees provide
        additional assurance to outside parties that contractual and statutory
        obligations will be met in a number of areas including construction contracts,
        environmental commitments and various retail transactions.
 
 FirstEnergy has guaranteed the obligations of the operators of the TEBSA
        project
        up to a maximum of $6 million (subject to escalation) under the project's
        operations and maintenance agreement. In connection with the sale of TEBSA
        in
        January 2004, the purchaser indemnified FirstEnergy against any loss under
        this
        guarantee. FirstEnergy has also provided an LOC ($36 million as of
        September 30, 2006) which is renewable and declines yearly based upon the
        senior outstanding debt of TEBSA. The LOC was reduced to $27 million on
        October 15, 2006.
 
 **OFF-BALANCE
        SHEET ARRANGEMENTS**
 
 FirstEnergy has obligations that are not included on its Consolidated Balance
        Sheets related to the sale and leaseback arrangements involving Perry, Beaver
        Valley Unit 2 and the Bruce Mansfield Plant, which are satisfied through
        operating lease payments. The present value of these sale and leaseback
        operating lease commitments, net of trust investments, total $1.3 billion
        as of September 30, 2006.
 
 FirstEnergy
        has
        equity ownership interests in certain businesses that are accounted for using
        the equity method. There are no undisclosed material contingencies related
        to
        these investments. Certain guarantees that FirstEnergy does not expect to
        have a
        material current or future effect on its financial condition, liquidity or
        results of operations are disclosed under Guarantees and Other Assurances
        above.
 
 **MARKET
        RISK
        INFORMATION**
 
 FirstEnergy uses various market risk sensitive instruments, including derivative
        contracts, primarily to manage the risk of price and interest rate fluctuations.
        FirstEnergy's Risk Policy Committee, comprised of members of senior management,
        provides general oversight to risk management activities throughout FirstEnergy
        and its subsidiaries.
 
 ***Commodity
        Price Risk***
 
 FirstEnergy is exposed to financial and market risks resulting from the
        fluctuation of interest rates and commodity prices primarily due to fluctuations
        in electricity, energy transmission, natural gas, coal, nuclear fuel and
        emission allowance prices. To manage the volatility relating to these exposures,
        FirstEnergy uses a variety of non-derivative and derivative instruments,
        including forward contracts, options, futures contracts and swaps. The
        derivatives are used principally for hedging purposes. Derivatives that fall
        within the scope of SFAS 133 must be recorded at their fair value and
        marked to market. The majority of FirstEnergy's derivative hedging contracts
        qualify for the normal purchase and normal sale exception under SFAS 133
        and are therefore excluded from the table below. Contracts that are not exempt
        from such treatment include the power purchase agreements with NUG entities
        that
        were structured pursuant to the Public Utility Regulatory Policies Act of
        1978.
        These non-trading contracts had been adjusted to fair value at the end of
        each
        quarter, with a corresponding regulatory asset recognized for above-market
        costs. On April 1, 2006, FirstEnergy elected to apply the normal purchase
        and
        normal sale exception to certain NUG power purchase agreements having a fair
        value of $13 million (included in “Other” in the table below) in accordance
        with guidance in DIG C20. The change in the fair value of commodity derivative
        contracts related to energy production during the three months and nine months
        ended September 30, 2006 is summarized in the following table:




57











**Three
                Months Ended**
            
            **Nine
                Months Ended****Increase
                (Decrease) in the Fair Value**
            **September
                30, 2006**
            
            **September
                30, 2006****of
                Commodity Derivative Contracts**
            **Non-Hedge**
            
            **Hedge**
            
            **Total**
            
            **Non-Hedge**
            
            **Hedge**
            
            **Total*****(In
                millions)*****Change
                in the Fair Value of****Commodity
                Derivative Contracts:**Outstanding
                net liability at beginning of period
            $
            (1,081
            )
            $
            (4
            )
            $
            (1,085
            )
            $
            (1,170
            )
            $
            (3
            )
            $
            (1,173
            )New
                contract
                value when entered
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Additions/change
                in value of existing contracts
            
            (164
            )
            
            (6
            )
            
            (170
            )
            
            (195
            )
            
            (16
            )
            
            (211
            )Change
                in
                techniques/assumptions
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Settled
                contracts
            
            85
            
            
            1
            
            
            86
            
            
            218
            
            
            10
            
            
            228Other
            
            -
            
            
            -
            
            
            -
            
            
            (13
            )
            
            -
            
            
            (13
            )Outstanding
                net liability at end of period(1)
            
            (1,160
            )
            
            (9
            )
            
            (1,169
            )
            
            (1,160
            )
            
            (9
            )
            
            (1,169
            )**Non-commodity
                Net Liabilities at End of Period:**Interest
                rate
                swaps(2)
            
            -
            
            
            (32
            )
            
            (32
            )
            
            -
            
            
            (32
            )
            
            (32
            )**Net
                Liabilities - Derivative Contracts**
              **at
                End
                of Period**
            $
            (1,160
            )
            $
            (41
            )
            $
            (1,201
            )
            $
            (1,160
            )
            $
            (41
            )
            $
            (1,201
            )**Impact
                of Changes in Commodity Derivative Contracts****(3)**Income
                Statement effects (pre-tax)
            $
            3
            
            $
            -
            
            $
            3
            
            $
            -
            
            $
            -
            
            $
            -Balance
                Sheet
                effects:Other
                comprehensive income (pre-tax)
            $
            -
            
            $
            (5
            )
            $
            (5
            )
            $
            -
            
            $
            (6
            )
            $
            (6
            )Regulatory
                assets (net)
            $
            82
            
            $
            -
            
            $
            82
            
            $
            (23
            )
            $
            -
            
            $
            (23
            )





(1)  Includes
      $1,160 million in non-hedge commodity derivative contracts (primarily with
      NUGs), which are offset by a regulatory asset.


(2)  Interest
      rate swaps
      are treated as cash flow or fair value hedges (see Interest Rate Swap Agreements
      below).


(3)  Represents
      the
      change in value of existing contracts, settled contracts and changes in
      techniques/assumptions.





Derivatives
      are
      included on the Consolidated Balance Sheet as of September 30, 2006 as
      follows:





**Balance
                Sheet Classification**
            
            **Non-Hedge**
            
            **Hedge**
            
            **Total*****(In
                millions)*****Current-**Other
                assets
            
            $
            -
            
            $
            10
            
            $
            10Other
                liabilities
            
            
            (1
            )
            
            (20
            )
            
            (21
            )**Non-Current-**Other
                deferred
                charges
            
            
            46
            
            
            4
            
            
            50Other
                noncurrent liabilities
            
            
            (1,205
            )
            
            (35
            )
            
            (1,240
            )Net
                liabilities
            
            $
            (1,160
            )
            $
            (41
            )
            $
            (1,201
            )





The
      valuation of
      derivative contracts is based on observable market information to the extent
      that such information is available. In cases where such information is not
      available, FirstEnergy relies on model-based information. The model provides
      estimates of future regional prices for electricity and an estimate of related
      price volatility. FirstEnergy uses these results to develop estimates of fair
      value for financial reporting purposes and for internal management decision
      making. Sources of information for the valuation of commodity derivative
      contracts as of September 30, 2006 are summarized by year in the following
      table:





**Source
                of Information****-
                Fair
                Value by Contract Year**
            
            **2006**(1)
            
            **2007**
            
            **2008**
            
            **2009**
            
            **2010**
            
            **Thereafter**
            
            **Total*****(In
                millions)***Prices
                actively quoted(2)
            
            $
            -
            
            $
            (2
            )
            $
            -
            
            $
            -
            
            $
            -
            
            $
            -
            
            $
            (2
            )Other
                external
                sources(3)
            
            
            (57
            )
            
            (270
            )
            
            (241
            )
            
            (191
            )
            
            -
            
            
            -
            
            
            (759
            )Prices
                based
                on models
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            (175
            )
            
            (233
            )
            
            (408
            )**Total****(4)**
            
            $
            (57
            )
            $
            (272
            )
            $
            (241
            )
            $
            (191
            )
            $
            (175
            )
            $
            (233
            )
            $
            (1,169
            )





(1)  For
      the last quarter
      of 2006.


(2)  Exchange
      traded.


(3)  Broker
      quote
      sheets.


(4)
            Includes
                $1,160 million in non-hedge commodity derivative contracts (primarily
                with NUGs), which are offset by a regulatory
                asset.





58








FirstEnergy performs sensitivity analyses to estimate its exposure to the market
      risk of its commodity positions. A hypothetical 10% adverse shift (an increase
      or decrease depending on the derivative position) in quoted market prices in
      the
      near term on its derivative instruments would not have had a material effect
      on
      its consolidated financial position (assets, liabilities and equity) or cash
      flows as of September 30, 2006. Based on derivative contracts held as of
      September 30, 2006, an adverse 10% change in commodity prices would
      decrease net income by approximately $1 million during the next 12 months.





***Interest
      Rate Swap Agreements - Fair Value Hedges***





FirstEnergy
      utilizes
      fixed-for-floating interest rate swap agreements as part of its ongoing effort
      to manage the interest rate risk associated with its debt portfolio. These
      derivatives are treated as fair value hedges of fixed-rate, long-term debt
      issues - designed to protect against the risk of changes in the fair value
      of
      fixed-rate debt instruments when interest rates decrease. Swap maturities,
      call
      options, fixed interest rates and interest payment dates match those of the
      underlying obligations. During the first nine months of 2006, FirstEnergy
      unwound swaps with a total notional amount of $350 million, for which
      FirstEnergy paid $1 million in cash. The loss will be recognized over the
      remaining term of each respective hedged security as increased interest expense.
      As of September 30, 2006, the debt underlying the $750 million
      outstanding notional amount of interest rate swaps had a weighted average fixed
      interest rate of 5.74%, which the swaps have converted to a current weighted
      average variable rate of 6.46%.





**September
                30, 2006**
            
            **December
                31, 2005****Notional**
            
            **Maturity**
            
            **Fair**
            
            **Notional**
            
            **Maturity**
            
            **Fair****Interest
                Rate Swaps**
            
            **Amount**
            
            **Date**
            
            **Value**
            
            **Amount**
            
            **Date**
            
            **Value*****(In
                millions)***(Fair
                value
                hedges)
            
            $
            100
            
            
            2008
            
            $
            (2
            )
            $
            100
            
            
            2008
            
            $
            (3
            )50
            
            
            2010
            
            
            (1
            )
            
            50
            
            
            2010
            
            
            --
            
            
            2011
            
            
            -
            
            
            50
            
            
            2011
            
            
            -300
            
            
            2013
            
            
            (7
            )
            
            450
            
            
            2013
            
            
            (4
            )150
            
            
            2015
            
            
            (10
            )
            
            150
            
            
            2015
            
            
            (9
            )-
            
            
            2016
            
            
            -
            
            
            150
            
            
            2016
            
            
            -50
            
            
            2025
            
            
            (2
            )
            
            50
            
            
            2025
            
            
            (1
            )100
            
            
            2031
            
            
            (7
            )
            
            100
            
            
            2031
            
            
            (5
            )$
            750
            
            
            
            
            $
            (29
            )
            $
            1,100
            
            
            
            
            $
            (22
            )





***Forward
      Starting Swap Agreements - Cash Flow Hedges***




FirstEnergy utilizes forward starting swap agreements (forward swaps) in order
      to hedge a portion of the consolidated interest rate risk associated with the
      anticipated future issuances of fixed-rate, long-term debt securities for one
      or
      more of its consolidated subsidiaries in 2006 through 2008. These derivatives
      are treated as cash flow hedges, protecting against the risk of changes in
      future interest payments resulting from changes in benchmark U.S. Treasury
      rates
      between the date of hedge inception and the date of the debt issuance. During
      the first nine months of 2006, FirstEnergy revised the tenor and timing of
      its
      financing plans. During the second quarter, FirstEnergy terminated forward
      swaps
      with an aggregate notional value of $600 million concurrent with its
      subsidiaries issuing long-term debt. FirstEnergy received $41 million in cash
      related to the termination. The gain associated with the ineffective portion
      of
      the terminated hedges ($6 million) was recognized in earnings, with the
      remainder to be recognized over the terms of the associated future debt. During
      the third quarter, FirstEnergy revised its financing plan related to swaps
      with
      $100 million notional value. FirstEnergy terminated and revised the forward
      swaps and performed an ineffectiveness assessment. FirstEnergy received cash
      of
      $2 million, all of which was effective and will be recognized in earnings
      over the terms of the associated future debt. As of September 30, 2006,
      FirstEnergy had outstanding forward swaps with an aggregate notional amount
      of
      $725 million and an aggregate fair value of ($2) million.





**September
                30, 2006**
            
            **December
                31, 2005****Notional**
            
            **Maturity**
            
            **Fair**
            
            **Notional**
            
            **Maturity**
            
            **Fair****Forward
                Starting Swaps**
            
            **Amount**
            
            **Date**
            
            **Value**
            
            **Amount**
            
            **Date**
            
            **Value*****(In
                millions)***(Cash
                flow
                hedges)
            
            $
            25
            
            
            2015
            
            $
            -
            
            $
            25
            
            
            2015
            
            $
            -300
            
            
            2016
            
            
            (1
            )
            
            600
            
            
            2016
            
            
            2200
            
            
            2017
            
            
            (3
            )
            
            25
            
            
            2017
            
            
            -150
            
            
            2018
            
            
            1
            
            
            275
            
            
            2018
            
            
            150
            
            
            2020
            
            
            1
            
            
            50
            
            
            2020
            
            
            -$
            725
            
            
            
            
            $
            (2
            )
            $
            975
            
            
            
            
            $
            3








59





***Equity
      Price Risk***





Included
      in nuclear
      decommissioning trusts are marketable equity securities carried at their market
      value of approximately $1.2 billion as of September 30, 2006 and
      $1.1 billion as of December 31, 2005. A hypothetical 10% decrease in
      prices quoted by stock exchanges would result in a $117 million reduction
      in fair value as of September 30, 2006.





**CREDIT
      RISK**




Credit risk is the risk of an obligor’s failure to meet the terms of an
      investment contract, loan agreement or otherwise perform as agreed. Credit
      risk
      arises from all activities in which success depends on issuer, borrower or
      counterparty performance, whether reflected on or off the balance sheet.
      FirstEnergy engages in transactions for the purchase and sale of commodities
      including gas, electricity, coal and emission allowances. These transactions
      are
      often with major energy companies within the industry.




FirstEnergy maintains credit policies with respect to its counterparties to
      manage overall credit risk. This includes performing independent risk
      evaluations, actively monitoring portfolio trends and using collateral and
      contract provisions to mitigate exposure. As part of its credit program,
      FirstEnergy aggressively manages the quality of its portfolio of energy
      contracts, evidenced by a current weighted average risk rating for energy
      contract counterparties of BBB (S&P). As of September 30, 2006, the
      largest credit concentration with one party (currently rated investment grade)
      represented 9.9% of FirstEnergy's total credit risk. Within FirstEnergy's
      unregulated energy subsidiaries, 99% of credit exposures, net of collateral
      and
      reserves, were with investment-grade counterparties as of September 30,
      2006.





**OUTLOOK**





***Regulatory
      Matters***





In Ohio, New Jersey and Pennsylvania, laws applicable to electric industry
      restructuring contain similar provisions that are reflected in the Companies'
      respective state regulatory plans. These provisions include:





·
            restructuring
                the electric generation business and allowing the Companies' customers
                to
                select a competitive electric generation supplier other than the
                Companies;·
            establishing
                or defining the PLR obligations to customers in the Companies' service
                areas;·
            providing
                the
                Companies with the opportunity to recover potentially stranded investment
                (or transition costs) not otherwise recoverable in a competitive
                generation market;·
            itemizing
                (unbundling) the price of electricity into its component elements
                -
                including generation, transmission, distribution and stranded costs
                recovery charges;·
            continuing
                regulation of the Companies' transmission and distribution systems;
                and·
            requiring
                corporate separation of regulated and unregulated business
                activities.





The
      Companies and
      ATSI recognize, as regulatory assets, costs which the FERC, PUCO, PPUC and
      NJBPU
      have authorized for recovery from customers in future periods or for which
      authorization is probable. Without the probability of such authorization, costs
      currently recorded as regulatory assets would have been charged to income as
      incurred. Regulatory assets that do not earn a current return totaled
      approximately $225 million as of September 30, 2006. The following
      table discloses the regulatory assets by company and by source:





60








**September
                30,**
            
            **December
                31,**
            
            **Increase****Regulatory
                Assets***
            
            **2006**
            
            **2005**
            
            **(Decrease)*****(In
                millions)***OE
            
            $
            746
            
            $
            775
            
            $
            (29
            )CEI
            
            
            855
            
            
            862
            
            
            (7
            )TE
            
            
            256
            
            
            287
            
            
            (31
            )JCP&L
            
            
            2,178
            
            
            2,227
            
            
            (49
            )Met-Ed
            
            
            365
            
            
            310
            
            
            55ATSI
            
            
            34
            
            
            25
            
            
            9Total
            
            $
            4,434
            
            $
            4,486
            
            $
            (52
            )





·
            Penn
                had net
                regulatory liabilities of approximately $64 million as of
                September 30, 2006 and $59 million as of December 31, 2005.
                Penelec had net regulatory liabilities of approximately $127 million
                and $163 million as of September 30, 2006 and December 31, 2005,
                respectively. These net regulatory liabilities are included in Other
                Non-current Liabilities on the Consolidated Balance Sheets.





Regulatory
      assets by
      source are as follows:





**September
                30,**
            
            **December
                31,**
            
            **Increase****Regulatory
                Assets By Source**
            
            **2006**
            
            **2005**
            
            **(Decrease)*****(In
                millions)***Regulatory
                transition costs
            
            $
            3,339
            
            $
            3,576
            
            $
            (237
            )Customer
                shopping incentives
            
            
            621
            
            
            884
            
            
            (263
            )Customer
                receivables for future income taxes
            
            
            214
            
            
            217
            
            
            (3
            )Societal
                benefits charge
            
            
            1
            
            
            29
            
            
            (28
            )Loss
                on
                reacquired debt
            
            
            40
            
            
            41
            
            
            (1
            )Employee
                postretirement benefits costs
            
            
            49
            
            
            55
            
            
            (6
            )Nuclear
                decommissioning, decontaminationand
                spent fuel
                disposal costs
            
            
            (135
            )
            
            (126
            )
            
            (9
            )Asset
                removal
                costs
            
            
            (168
            )
            
            (365
            )
            
            197Property
                losses and unrecovered plant costs
            
            
            21
            
            
            29
            
            
            (8
            )MISO/PJM
                transmission costs
            
            
            177
            
            
            91
            
            
            86Fuel
                costs -
                RCP
            
            
            94
            
            
            -
            
            
            94Distribution
                costs - RCP
            
            
            121
            
            
            -
            
            
            121JCP&L
                reliability costs
            
            
            16
            
            
            23
            
            
            (7
            )Other
            
            
            44
            
            
            32
            
            
            12Total
            
            $
            4,434
            
            $
            4,486
            
            $
            (52
            )




***Reliability
      Initiatives***




FirstEnergy is proceeding with the implementation of the recommendations that
      were issued from various entities, including governmental, industry and ad
      hoc
      reliability entities (PUCO, FERC, NERC and the U.S. - Canada Power System Outage
      Task Force) in late 2003 and early 2004, regarding enhancements to regional
      reliability that were to be completed subsequent to 2004. FirstEnergy will
      continue to periodically assess the FERC-ordered Reliability Study
      recommendations for forecasted 2009 system conditions, recognizing revised
      load
      forecasts and other changing system conditions which may impact the
      recommendations. Thus far, implementation of the recommendations has not
      required, nor is expected to require, substantial investment in new, or material
      upgrades to existing, equipment. The FERC or other applicable government
      agencies and reliability coordinators, however, may take a different view as
      to
      recommended enhancements or may recommend additional enhancements in the future
      as the result of adoption of mandatory reliability standards pursuant to EPACT
      that could require additional, material expenditures.





61




As a result of outages experienced in JCP&L’s service area in 2002 and 2003,
      the NJBPU had implemented reviews into JCP&L’s service reliability. In 2004,
      the NJBPU adopted an MOU that set out specific tasks related to service
      reliability to be performed by JCP&L and a timetable for completion and
      endorsed JCP&L’s ongoing actions to implement the MOU. On June 9, 2004,
      the NJBPU approved a Stipulation that incorporates the final report of an SRM
      who made recommendations on appropriate courses of action necessary to ensure
      system-wide reliability. The Stipulation also incorporates the Executive Summary
      and Recommendation portions of the final report of a focused audit of
      JCP&L’s Planning and Operations and Maintenance programs and practices
      (Focused Audit). A final order in the Focused Audit docket was issued by the
      NJBPU on July 23, 2004. On February 11, 2005, JCP&L met with the
      DRA to discuss reliability improvements. The SRM completed his work and issued
      his final report to the NJBPU on June 1, 2006. A meeting was held between
      JCP&L and the NJBPU on June 29, 2006 to discuss the SRM’s final report.
      JCP&L filed a comprehensive response to the NJBPU on July 14, 2006.
      JCP&L continues to file compliance reports reflecting activities associated
      with the MOU and Stipulation.




EPACT provides for the creation of an ERO to establish and enforce reliability
      standards for the bulk power system, subject to FERC’s review. On
      February 3, 2006, the FERC adopted a rule establishing certification
      requirements for the ERO, as well as regional entities envisioned to assume
      monitoring responsibility for the new reliability standards. The FERC issued
      an
      order on rehearing on March 30, 2006, providing certain clarifications and
      essentially affirming the rule.




The NERC has been preparing the implementation aspects of reorganizing its
      structure to meet the FERC’s certification requirements for the ERO. The NERC
      made a filing with the FERC on April 4, 2006 to obtain certification as the
      ERO and to obtain FERC approval of delegation agreements with regional
      reliability organizations (regional entities). The new FERC rule referred to
      above, further provides for reorganizing regional entities that would replace
      the current regional councils and for rearranging their relationship with the
      ERO. The “regional entity” may be delegated authority by the ERO, subject to
      FERC approval, for enforcing reliability standards adopted by the ERO and
      approved by the FERC. The ERO filing was noticed on April 7, 2006 and comments
      and reply comments were filed in May, June and July 2006. On July 20, 2006,
      the
      FERC certified the NERC as the ERO to implement the provisions of Section 215
      of
      the Federal Power Act and directed the NERC to make a compliance filing within
      90 days addressing such issues as the regional delegation agreements. The NERC
      made its compliance filing in October 2006. This filing is pending before the
      FERC.





On
      April 4, 2006,
      NERC also submitted a filing with the FERC seeking approval of mandatory
      reliability standards. These reliability standards are based, with some
      modifications and additions, on the current NERC Version O reliability
      standards. The reliability standards filing was noticed by the FERC on April
      18,
      2006. In that notice, the FERC announced its intent to issue a Notice of
      Proposed Rulemaking on the proposed reliability standards at a future date.
      On
      May 11, 2006, the FERC staff released a preliminary assessment that cited
      many deficiencies in the proposed reliability standards. The NERC and industry
      participants filed comments in response to the Staff’s preliminary assessment.
      The FERC held a technical conference on the proposed reliability standards
      on
      July 6, 2006. The FERC issued a Notice of Proposed Rulemaking on the proposed
      reliability standards on October 20, 2006. The FERC voted to adopt 83 of
      the proposed 107 reliability standards. The FERC asked the NERC to make
      technical improvements to 62 of the 83 standards approved. The 24 standards
      that
      were not adopted remain pending at the FERC awaiting further clarification
      and
      filings by the NERC and regional entities. The FERC also provided additional
      clarification on the proposed application of final standards in the NOPR.
      Interested parties will be given the opportunity to comment on the NOPR within
      60 days of its publication in the Federal Register. Mandatory reliability
      standards are expected to be in place by the summer of 2007. In a separate
      order
      issued October 24, 2006, the FERC approved NERC’s 2007 budget and business
      plan subject to certain compliance filings.




The ECAR, Mid-Atlantic Area Council, and Mid-American Interconnected Network
      reliability councils have completed the consolidation of these regions into
      a
      single new regional reliability organization known as ReliabilityFirst
      Corporation. ReliabilityFirst began operations as a regional reliability council
      under NERC on January 1, 2006 and intends to file and obtain certification
      consistent with the final rule as a “regional entity” under the ERO during 2006.
      All of FirstEnergy’s facilities are located within the ReliabilityFirst
      region.




On May 2, 2006, the NERC Board of Trustees adopted eight new cyber security
      standards that replaced interim standards put in place in the wake of the
      September 11, 2001 terrorist attacks, and thirteen additional reliability
      standards. The security standards became effective on June 1, 2006, and the
      remaining standards will become effective throughout 2006 and 2007. NERC intends
      to file the standards with the FERC and relevant Canadian authorities for
      approval, but the cyber security standards were not included in the
      October 20, 2006 NOPR.





62




FirstEnergy believes that it is in compliance with all current NERC reliability
      standards. However, based upon a review of the October 20, 2006 NOPR, it
      appears that the FERC will adopt stricter reliability standards than those
      contained in the current NERC standards. The financial impact of complying
      with
      the new standards cannot be determined at this time. However, EPACT requires
      that all prudent costs incurred to comply with the new reliability standards
      be
      recovered in rates. If FirstEnergy is unable to meet the reliability standards
      for the bulk power system in the future, it could have a material adverse effect
      on the Company’s and its subsidiaries’ financial condition, results of
      operations and cash flows.





See
      Note 11 to
      the consolidated financial statements for a more detailed discussion of
      reliability initiatives.





***Ohio***





On
      October 21, 2003,
      the Ohio Companies filed their RSP case with the PUCO. On August 5, 2004, the
      Ohio Companies accepted the RSP as modified and approved by the PUCO in an
      August 4, 2004 Entry on Rehearing, subject to a CBP. The RSP was intended to
      establish generation service rates beginning January 1, 2006, in response to
      the
      PUCO’s concerns about price and supply uncertainty following the end of the Ohio
      Companies' transition plan market development period. In October 2004, the
      OCC
      and NOAC filed appeals with the Supreme Court of Ohio to overturn the original
      June 9, 2004 PUCO order in the proceeding as well as the associated entries
      on
      rehearing. On May 3, 2006, the Supreme Court of Ohio issued an opinion affirming
      the PUCO's order with respect to the approval of the rate stabilization charge,
      approval of the shopping credits, the granting of interest on shopping credit
      incentive deferral amounts, and approval of the Ohio Companies’ financial
      separation plan. It remanded back to the PUCO the matter of ensuring the
      availability of sufficient means for customer participation in the competitive
      marketplace. The RSP contained a provision that permitted the Ohio Companies
      to
      withdraw and terminate the RSP in the event that the PUCO, or the Supreme Court
      of Ohio, rejected all or part of the RSP. In such event, the Ohio Companies
      have
      30 days from the final order or decision to provide notice of termination.
      On
      July 20, 2006 the Ohio Companies filed with the PUCO a Request to Initiate
      a
      Proceeding on Remand. In their Request, the Ohio Companies provided notice
      of
      termination to those provisions of the RSP subject to termination, subject
      to
      being withdrawn, and also set forth a framework for addressing the Supreme
      Court
      of Ohio’s findings on customer participation, requesting the PUCO to initiate a
      proceeding to consider the Ohio Companies’ proposal. If the PUCO approves a
      resolution to the issues raised by the Supreme Court of Ohio that is acceptable
      to the Ohio Companies, the Ohio Companies’ termination will be withdrawn and
      considered to be null and void. Separately, the OCC and NOAC also submitted
      to
      the PUCO on July 20, 2006 a conceptual proposal dealing with the issue raised
      by
      the Supreme Court of Ohio. On July 26, 2006, the PUCO issued an Entry
      acknowledging the July 20, 2006 filings of the Ohio Companies and the OCC and
      NOAC, and giving the Ohio Companies 45 days to file a plan in a new docket
      to
      address the Court’s concern. On September 19, 2006, the PUCO issued an
      Entry granting the Ohio Companies’ motion for extension of time to file the
      remand proposal. The Ohio Companies filed their RSP Remand CBP on
      September 29, 2006. No further proceedings have been scheduled at this
      time.




The Ohio Companies filed an application and stipulation with the PUCO on
      September 9, 2005 seeking approval of the RCP, a supplement to the RSP. On
      November 4, 2005, the Ohio Companies filed a supplemental stipulation with
      the
      PUCO, which constituted an additional component of the RCP filed on September
      9,
      2005. Major provisions of the RCP include:





●
            Maintaining
                the existing level of base distribution rates through December 31,
                2008 for OE and TE, and April 30, 2009 for CEI;●
            Deferring
                and
                capitalizing for future recovery (over a 25-year period) with carrying
                charges certain distribution costs to be incurred during the period
                January 1, 2006 through December 31, 2008, not to exceed
                $150 million in each of the three years;●
            Adjusting
                the
                RTC and extended RTC recovery periods and rate levels so that full
                recovery of authorized costs will occur as of December 31, 2008 for
                OE and TE and as of December 31, 2010 for CEI;●
            Reducing
                the
                deferred shopping incentive balances as of January 1, 2006 by up to
                $75 million for OE, $45 million for TE, and $85 million for CEI
                by accelerating the application of each respective company's accumulated
                cost of removal regulatory liability; and●
            Recovering
                increased fuel costs (compared to a 2002 baseline) of up to $75 million,
                $77 million, and $79 million, in 2006, 2007, and 2008,
                respectively, from all OE and TE distribution and transmission customers
                through a fuel recovery mechanism. OE, TE, and CEI may defer and
                capitalize (for recovery over a 25-year period) increased fuel costs
                above
                the amount collected through the fuel recovery mechanism.








63








The following table provides the estimated net amortization of regulatory
      transition costs and deferred shopping incentives (including associated carrying
      charges) under the RCP for the period 2006 through 2010:





**Amortization**
            
            
            
            
            
            
            
            **Total****Period**
            
            **OE**
            
            **CEI**
            
            **TE**
            
            **Ohio*****(In
                millions)***2006
            
            $
            173
            
            $
            96
            
            $
            87
            
            $
            3562007
            
            
            180
            
            
            113
            
            
            90
            
            
            3832008
            
            
            207
            
            
            130
            
            
            112
            
            
            4492009
            
            
            -
            
            
            211
            
            
            -
            
            
            2112010
            
            
            -
            
            
            264
            
            
            -
            
            
            264**Total
                Amortization**
            
            **$**
            **560**
            
            **$**
            **814**
            
            **$**
            **289**
            
            **$**
            **1,663**




On January 4, 2006, the PUCO approved, with modifications, the Ohio Companies’
RCP to supplement the RSP to provide customers with more certain rate levels
      than otherwise available under the RSP during the plan period. On
      January 10,
      2006, the Ohio Companies filed a Motion for Clarification of the PUCO order
      approving the RCP. The Ohio Companies sought clarity on issues related to
      distribution deferrals, including requirements of the review process, timing
      for
      recognizing certain deferrals and definitions of the types of qualified
      expenditures. The Ohio Companies also sought confirmation that the list of
      deferrable distribution expenditures originally included in the revised
      stipulation fall within the PUCO order definition of qualified expenditures.
      On
      January 25, 2006, the PUCO issued an Entry on Rehearing granting in part,
      and denying in part, the Ohio Companies’ previous requests and clarifying issues
      referred to above. The PUCO granted the Ohio Companies’ requests to:





·
            Recognize
                fuel
                and distribution deferrals commencing January 1,
                2006;·
            Recognize
                distribution deferrals on a monthly basis prior to review by the
                PUCO
                Staff;·
            Clarify
                that
                the types of distribution expenditures included in the Supplemental
                Stipulation may be deferred; and·
            Clarify
                that
                distribution expenditures do not have to be “accelerated” in order to be
                deferred.




The PUCO approved the Ohio Companies’ methodology for determining distribution
      deferral amounts, but denied the Motion in that the PUCO Staff must verify
      the
      level of distribution expenditures contained in current rates, as opposed to
      simply accepting the amounts contained in the Ohio Companies’ Motion. On
      February 3, 2006, several other parties filed applications for rehearing on
      the PUCO's January 4, 2006 Order. The Ohio Companies responded to the
      applications for rehearing on February 13, 2006. In an Entry on Rehearing
      issued by the PUCO on March 1, 2006, all motions for rehearing were denied.
      Certain of these parties have subsequently filed notices of appeal with the
      Supreme Court of Ohio alleging various errors made by the PUCO in its order
      approving the RCP. The Ohio Companies’ Motion to Intervene in the appeals was
      granted by the Supreme Court on June 8, 2006. The Appellants’ Merit Briefs were
      filed at the Supreme Court on July 5, 2006. The Appellees include the PUCO
      and the Ohio Companies. The Appellees’ Merit Briefs were filed on
      August 24, 2006 and the Appellants’ Reply Briefs were filed on
      September 21, 2006. The OCC filed an amicus brief on August 4, 2006,
      which the Ohio Companies moved to strike as improperly filed. The Supreme Court
      denied the Ohio Companies’ motion on October 18, 2006.




On December 30, 2004, the Ohio Companies filed with the PUCO two
      applications related to the recovery of transmission and ancillary service
      related costs. The first application sought recovery of these costs beginning
      January 1, 2006. The Ohio Companies requested that these costs be recovered
      through a rider that would be effective on January 1, 2006 and adjusted
      each July 1 thereafter. The parties reached a settlement agreement that was
      approved by the PUCO on August 31, 2005. The incremental transmission and
      ancillary service revenues recovered from January 1 through June 30, 2006
      were approximately $61 million. That amount included the recovery of a
      portion of the 2005 deferred MISO expenses as described below. On April 27,
      2006, the Ohio Companies filed the annual update rider to determine revenues
      ($139 million) from July 2006 through June 2007. The filed rider went into
      effect on July 1, 2006.





64





The
      second
      application sought authority to defer costs associated with transmission and
      ancillary service related costs incurred during the period October 1, 2003
      through December 31, 2005. On May 18, 2005, the PUCO granted the
      accounting authority for the Ohio Companies to defer incremental transmission
      and ancillary service-related charges incurred as a participant in MISO, but
      only for those costs incurred during the period December 30, 2004 through
      December 31, 2005. Permission to defer costs incurred prior to
      December 30, 2004 was denied. The PUCO also authorized the Ohio Companies
      to accrue carrying charges on the deferred balances. On August 31, 2005,
      the OCC appealed the PUCO's decision. On
      January 20,
      2006, the OCC sought rehearing of the PUCO’s approval of the recovery of
      deferred costs through the rider during the period January 1, 2006 through
      June 30, 2006. The PUCO denied the OCC's application on February 6,
      2006. On March 23, 2006, the OCC appealed the PUCO's order to the Ohio
      Supreme Court. On March 27, 2006, the OCC filed a motion to consolidate
      this appeal with the deferral appeals discussed above and to postpone oral
      arguments in the deferral appeal until after all briefs are filed in this most
      recent appeal of the rider recovery mechanism. On
      March 20, 2006,
      the Ohio Supreme Court, on its own motion, consolidated the OCC's appeal of
      the
      Ohio Companies' case with a similar case involving Dayton Power & Light
      Company. Oral arguments were heard on May 10, 2006. The Ohio Companies are
      awaiting a final ruling from the Ohio Supreme Court, which is expected before
      the end of 2006.





See
      Note 11 to
      the consolidated financial statements for further details and a complete
      discussion of regulatory matters in Ohio.





***Pennsylvania***




Met-Ed and Penelec purchase a portion of their PLR requirements from FES through
      a wholesale power sales agreement. Under this agreement, FES retains the supply
      obligation and the supply profit and loss risk for the portion of power supply
      requirements not self-supplied by Met-Ed and Penelec under their contracts
      with
      NUGs and other unaffiliated suppliers. The FES arrangement reduces Met-Ed's
      and
      Penelec's exposure to high wholesale power prices by providing power at a fixed
      price for their uncommitted PLR energy costs during the term of the agreement
      with FES. The wholesale power sales agreement with FES could automatically
      be
      extended for each successive calendar year unless any party elects to cancel
      the
      agreement by November 1 of the preceding year. On November 1, 2005, FES and
      the other parties thereto amended the agreement to provide FES the right in
      2006
      to terminate the agreement at any time upon 60 days notice. On
      April 7, 2006, the parties to the wholesale power sales agreement entered
      into a Tolling Agreement that arises out of FES’ notice to Met-Ed and Penelec
      that FES elected to exercise its right to terminate the wholesale power sales
      agreement effective midnight December 31, 2006, because that agreement is
      not economically sustainable to FES.




In lieu of allowing such termination to become effective as of December 31,
      2006, the parties agreed, pursuant to the Tolling Agreement, to amend the
      wholesale power sales agreement to provide as follows:





1.  The
      termination
      provisions of the wholesale power sales agreement will be tolled for one year
      until December 31, 2007, provided that during such tolling
      period:


a.  FES
      will be
      permitted to terminate the wholesale power sales agreement at any time with
      sixty days written notice;


b.  Met-Ed
      and Penelec
      will procure through arrangements other than the wholesale power sales agreement
      beginning December 1, 2006 and ending December 31, 2007, approximately
      33% of the amounts of capacity and energy necessary to satisfy their PLR
      obligations for which Committed Resources (i.e., non-utility generation under
      contract to Met-Ed and Penelec, Met-Ed- and Penelec-owned generating facilities,
      purchased power contracts and distributed generation) have not been obtained;
      and


c.  FES
      will not be
      obligated to supply additional quantities of capacity and energy in the event
      that a supplier of Committed Resources defaults on its supply
      agreement;





2.  During
      the tolling
      period, FES will not act as an agent for Met-Ed or Penelec in procuring the
      services under 1.(b) above; and





3.  The
      pricing
      provision of the wholesale power sales agreement shall remain unchanged provided
      Met-Ed and Penelec comply with the provisions of the Tolling Agreement and
      any
      applicable provision of the wholesale power sales agreement.





In
      the event that
      FES elects not to terminate the wholesale power sales agreement effective
      midnight December 31, 2007, similar tolling agreements effective after
      December 31, 2007 are expected to be considered by FES for subsequent years
      if Met-Ed and Penelec procure through arrangements other than the wholesale
      power sales agreement approximately 64%, 83% and 95% of the additional amounts
      of capacity and energy necessary to satisfy their PLR obligations for 2008,
      2009
      and 2010, respectively, for which Committed Resources have not been obtained
      from the market. On September 26, 2006, Met-Ed and Penelec successfully
      conducted a competitive RFP for 33% of their PLR obligation for which Committed
      Resources have not been obtained for the period December 1, 2006 through
      December 31, 2008.





65





The
      wholesale power
      sales agreement, as modified by the Tolling Agreement, requires Met-Ed and
      Penelec to satisfy the portion of their PLR obligations currently supplied
      by
      FES from unaffiliated suppliers at prevailing prices, which are likely to be
      higher than the current price charged by FES under the current agreement and,
      as
      a result, Met-Ed’s and Penelec’s purchased power costs could materially
      increase. If Met-Ed and Penelec were to replace the entire FES supply at current
      market power prices without corresponding regulatory authorization to increase
      their generation prices to customers, each company would likely incur a
      significant increase in operating expenses and experience a material
      deterioration in credit quality metrics. Under such a scenario, each company's
      credit profile would no longer be expected to support an investment grade rating
      for its fixed income securities. There can be no assurance, however, that if
      FES
      ultimately determines to terminate, further reduce, or significantly modify
      the
      agreement, timely regulatory relief will be granted by the PPUC pursuant to
      the
      April 10, 2006 comprehensive rate filing discussed below, or, to the extent
      granted, adequate to mitigate such adverse consequences.





Met-Ed
      and Penelec
      made a comprehensive rate filing with the PPUC on April 10, 2006 that
      addresses a number of transmission, distribution and supply issues. If Met-Ed's
      and Penelec's preferred approach involving accounting deferrals is approved,
      the
      filing would increase annual revenues by $216 million and
      $157 million, respectively. That filing includes, among other things, a
      request to charge customers for an increasing amount of market priced power
      procured through a CBP as the amount of supply provided under the existing
      FES
      agreement is phased out in accordance with the April 7, 2006 Tolling
      Agreement described above. Met-Ed
      and Penelec
      also requested approval of the January 12, 2005 petition for the deferral
      of transmission-related costs discussed above, but only for those costs incurred
      during 2006. In this rate filing, Met-Ed and Penelec also requested recovery
      of
      annual transmission and related costs incurred on or after January 1, 2007,
      plus the amortized portion of 2006 costs over a ten-year period, along with
      applicable carrying charges, through an adjustable rider similar to that
      implemented in Ohio. Changes in the
      recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs
      are
      also included in the filing. The filing contemplates a reduction in distribution
      rates for Met-Ed of $37 million annually and an increase in distribution
      rates for Penelec of $20 million annually. The PPUC suspended the effective
      date (June 10, 2006) of these rate changes for seven months after the
      filing as permitted under Pennsylvania law. If the PPUC adopts the overall
      positions taken in the intervenors’ testimony as filed, this would have a
      material adverse effect on the financial statements of FirstEnergy, Met-Ed
      and
      Penelec. Hearings were held in late August 2006 and all reply briefs were filed
      by October 6, 2006. The ALJ’s recommended decision is due by November 8,
      2006 and the PPUC decision is expected by January 12, 2007.





As
      of
      September 30, 2006, Met-Ed's and Penelec's regulatory deferrals pursuant to
      the 1998 Restructuring Settlement (including the Phase 2 Proceedings) and the
      FirstEnergy/GPU Merger Settlement Stipulation were $297 million and
      $56 million, respectively. Penelec's $56 million is subject to the
      pending resolution of taxable income issues associated with NUG trust fund
      proceeds. The PPUC recently conducted a review and audit of a modification
      to
      the NUG purchased power stranded cost accounting methodology for Met-Ed and
      Penelec. On August 18, 2006, a PPUC Order was entered requiring Met-Ed and
      Penelec to reflect the deferred NUG cost balances as if the stranded cost
      accounting methodology modification had not been implemented. As a result of
      the
      PPUC’s Order, Met-Ed recognized a pre-tax charge of approximately $10.3 million
      in the third quarter of 2006, representing incremental costs deferred under
      the
      revised methodology in 2005. Met-Ed and Penelec continue to believe that the
      stranded cost accounting methodology modification is appropriate and filed
      a
      petition with the PPUC pursuant to its Order for authorization to reflect the
      stranded cost accounting methodology modification effective January 1, 1999.





On January 12, 2005, Met-Ed and Penelec filed, before the PPUC, a request
      for deferral of transmission-related costs beginning January 1, 2005. The
      OCA, OSBA, OTS, MEIUG, PICA, Allegheny Electric Cooperative and Pennsylvania
      Rural Electric Association all intervened in the case. Met-Ed and Penelec sought
      to consolidate this proceeding (and modified their request to provide deferral
      of 2006 transmission-related costs only) with the comprehensive rate filing
      they
      made on April 10, 2006 as described above. On May 4, 2006, the PPUC
      approved the modified request. Accordingly, Met-Ed and Penelec have deferred
      approximately $90 million and $21 million, respectively, representing
      transmission costs that were incurred from January 1, 2006 through
      September 30, 2006. On June 5, 2006, the OCA filed before the
      Commonwealth Court a petition for review of the PPUC’s approval of the deferral.
      On July 12, 2006, the Commonwealth Court granted the PPUC’s motion to quash the
      OCA’s appeal. The ratemaking treatment of the deferrals will be determined in
      the comprehensive rate filing proceeding discussed further above.





66







Under Pennsylvania's electric competition law, Penn is required to secure
      generation supply for customers who do not choose alternative suppliers for
      their electricity. On October 11, 2005, Penn filed a plan with the PPUC to
      secure electricity supply for its customers at set rates following the end
      of
      its transition period on December 31, 2006. Penn recommended that the RFP
      process cover the period January 1, 2007 through May 31, 2008.
      Hearings before the PPUC were held on January 10, 2006 with main briefs
      filed on January 27, 2006 and reply briefs filed on February 3, 2006.
      On February 16, 2006, the ALJ issued a Recommended Decision to adopt Penn's
      RFP process with modifications. On April 20, 2006, the PPUC approved the
      Recommended Decision with additional modifications to use an RFP process with
      two separate solicitations. An initial solicitation was held for Penn in May
      2006 with all tranches fully subscribed, which was approved by the PPUC on
      June 2, 2006. On July 18, 2006, the second PLR solicitation was held for
      Penn. The tranches for the Residential Group and Small Commercial Group were
      fully subscribed. However, supply was not acquired for two tranches for the
      Large Commercial Group. On July 20, 2006, the PPUC approved the submissions
      for
      the second bid. A contingency solicitation was held on August 15, 2006 for
      the two remaining Large Commercial Group tranches. The PPUC rejected the bids
      from the contingency solicitation and directed Penn’s independent auction
      manager to offer the two unfilled Large Commercial tranches to the companies
      which had won tranches in the prior solicitations. This resulted in the
      acquisition of a supplier for the two remaining tranches, which were filed
      and
      accepted by the PPUC in a secretarial letter that was entered on
      September 22, 2006. On August 24, 2006, Penn made a compliance filing.
      OCA and OSBA filed exceptions to the compliance filing. Penn filed reply
      exceptions on September 5, 2006. On September 21, 2006, Penn submitted
      a revised compliance filing to the PPUC for the Residential Group and Small
      Commercial Group as a result of an agreement between Penn, OCA and OSBA. The
      PPUC approved proposed rates for the large commercial and industrial customers
      at the PPUC Public meeting on October 19, 2006, and found that the results
      of the competitive solicitation process were consistent with prevailing market
      prices.




On May 25, 2006, Penn filed a Petition for Review of the PPUC’s Orders of
      April 28, 2006 and May 4, 2006, which together decided the issues
      associated with Penn’s proposed Interim PLR Supply Plan. Penn has asked the
      Commonwealth Court to review the PPUC’s decision to deny Penn’s recovery of
      certain PLR costs through a reconciliation mechanism and the PPUC’s decision to
      impose a geographic limitation on the sources of alternative energy credits.
      On
      June 7, 2006, the PaDEP filed a Petition for Review appealing the PPUC’s
      ruling on the method by which alternative energy credits may be acquired and
      traded. Penn is unable to predict the outcome of this appeal.




See Note 11 to the consolidated financial statements for further details
      and a complete discussion of regulatory matters in Pennsylvania.




***New
      Jersey***




JCP&L is permitted to defer for future collection from customers the amounts
      by which its costs of supplying BGS to non-shopping customers and costs incurred
      under NUG agreements exceed amounts collected through BGS and NUGC rates and
      market sales of NUG energy and capacity. As of September 30, 2006, the
      accumulated deferred cost balance totaled approximately $340 million. New
      Jersey law allows for securitization of JCP&L's deferred balance upon
      application by JCP&L and a determination by the NJBPU that the conditions of
      the New Jersey restructuring legislation are met. On February 14, 2003,
      JCP&L filed for approval to securitize the July 31, 2003 deferred balance.
      On June 8, 2006, the NJBPU approved JCP&L’s request to issue securitization
      bonds associated with BGS stranded cost deferrals. On August 10, 2006,
      JCP&L Transition Funding II, a wholly owned subsidiary of JCP&L, issued
      $182 million of transition bonds with a weighted average interest rate of
      5.5%.





On
      December 2,
      2005, JCP&L filed its request for recovery of $165 million of actual
      above-market NUG costs incurred from August 1, 2003 through
      October 31, 2005 and forecasted above-market NUG costs for November and
      December 2005. On February 23, 2006, JCP&L filed updated data reflecting
      actual amounts through December 31, 2005 of $154 million of costs
      incurred since July 31, 2003. On March 29, 2006, a pre-hearing
      conference was held with the presiding ALJ. On July 18, 2006, JCP&L
      filed rebuttal testimony that included a request for an additional
      $14 million of costs that had been eliminated from the securitized amount.
      Evidentiary hearings were held during September 2006 and the briefing schedule
      has been postponed pending settlement discussions.




An NJBPU Decision and Order approving a Phase II Stipulation of Settlement
      and
      resolving the Motion for Reconsideration of the Phase I Order was issued on
      May
      31, 2005. The Phase II Settlement includes a performance standard pilot program
      with potential penalties of up to 0.25% of allowable equity return. The Order
      requires that JCP&L file quarterly reliability reports (CAIDI and SAIFI
      information related to the performance pilot program) through December 2006
      and
      updates to reliability related project expenditures until all projects are
      completed. The latest quarterly reliability reports were submitted on
      September 12, 2006. As of September 30, 2006, there were no
      performance penalties issued by the NJBPU.





67




Reacting to the higher closing prices of the 2006 BGS fixed rate auction, the
      NJBPU, on March 16, 2006, initiated a generic proceeding to evaluate the
      auction process and potential options for the future. On April 6, 2006,
      initial comments were submitted. A public meeting was held on April 21, 2006
      and
      a legislative-type hearing was held on April 28, 2006. On June 21, 2006,
      the NJBPU approved the continued use of a descending block auction for the
      Fixed
      Price Residential Class. JCP&L filed its 2007 BGS company specific addendum
      on July 10, 2006. On October 27, 2006, the NJBPU approved the auction
      format to procure the 2007 Commercial Industrial Energy Price as well as the
      specific rules for both the Fixed Price and Commercial Industrial Energy Price
      auctions. These rules were essentially unchanged from the prior
      auctions.





On
      August 1,
      2005, the NJBPU established a proceeding to determine whether additional
      ratepayer protections are required at the state level in light of the repeal
      of
      PUHCA pursuant to the EPACT. An NJBPU proposed rulemaking to address the issues
      was published in the NJ Register on December 19, 2005. The proposal would
      prevent a holding company that owns a gas or electric public utility from
      investing more than 25% of the combined assets of its utility and
      utility-related subsidiaries into businesses unrelated to the utility industry.
      A public hearing was held on February 7, 2006 and comments were submitted
      to the NJBPU. On August 16, 2006, the NJBPU approved the regulations with
      an effective date of October 2, 2006. These regulations are not expected to
      materially impact FirstEnergy or JCP&L. Also in the same proceeding, the
      NJBPU Staff issued an additional draft proposal on March 31, 2006
      addressing various issues including access to books and records, ring-fencing,
      cross subsidization, corporate governance and related matters. With the approval
      of the NJBPU Staff, the affected utilities jointly submitted an alternative
      proposal on June 1, 2006. Comments on the alternative proposal were submitted
      on
      June 15, 2006.




See Note 11 to the consolidated financial statements for further details
      and a complete discussion of regulatory matters in New Jersey.





***FERC
      Matters***





On
      November 1, 2004,
      ATSI filed with the FERC a request to defer approximately $54 million of costs
      to be incurred from 2004 through 2007 in connection with ATSI’s VMEP, which
      represents ATSI’s adoption of newly identified industry “best practices” for
      vegetation management. On March 4, 2005, the FERC approved ATSI’s request to
      defer the VMEP costs (approximately $34 million has been deferred as of
      September 30, 2006). On March 28, 2006, ATSI and MISO filed with the FERC a
      request to modify ATSI’s Attachment O formula rate to include revenue
      requirements associated with recovery of deferred VMEP costs over a five-year
      period. The requested effective date to begin recovery was June 1, 2006. Various
      parties filed comments responsive to the March 28, 2006 submission. The FERC
      conditionally approved the filing on May 22, 2006, subject to a compliance
      filing that ATSI made on June 13, 2006. A request for rehearing of the FERC’s
      May 22, 2006 Order was filed by a party, which ATSI answered. On July 14,
      2006, the FERC accepted ATSI’s June 13, 2006 compliance filing. The estimated
      annual revenues to ATSI from the VMEP cost recovery is $12 million for each
      of
      the five years beginning June 1, 2006. On October 25, 2006, the FERC
      denied the request for rehearing.





On
      January 24, 2006,
      ATSI and MISO filed a request with the FERC to correct ATSI’s Attachment O
      formula rate to reverse revenue credits associated with termination of revenue
      streams from transitional rates stemming from FERC’s elimination of RTOR.
      Revenues formerly collected under these rates were included in, and served
      to
      reduce, ATSI’s zonal transmission rate under the Attachment O formula. Absent
      the requested correction, elimination of these revenue streams would not be
      fully reflected in ATSI’s formula rate until June 1, 2008. On March 16, 2006,
      the FERC approved the revenue credit correction without suspension, effective
      April 1, 2006. One party sought rehearing of the FERC's order. The request
      for
      rehearing of this order was denied on June 27, 2006. The FERC accepted MISO’s
      and ATSI’s revised tariff sheets for filing on June 7, 2006. The estimated
      annual revenue impact of the correction mechanism is approximately $40 million
      effective on June 1, 2006.





On
      November 18,
      2004, the FERC issued an order eliminating the RTOR for transmission service
      between the MISO and PJM regions. The FERC also ordered the MISO, PJM and the
      transmission owners within MISO and PJM to submit compliance filings containing
      a SECA mechanism to recover lost RTOR revenues during a 16-month transition
      period from load serving entities. The FERC issued orders in 2005 setting the
      SECA for hearing. ATSI, JCP&L, Met-Ed, Penelec, and FES continue to be
      involved in the FERC hearings concerning the calculation and imposition of
      the
      SECA charges. The hearing was held in May 2006. Initial briefs were submitted
      on
      June 9, 2006, and reply briefs were filed on June 27, 2006. The Presiding Judge
      issued an Initial Decision on August 10, 2006, rejecting the compliance filings
      made by the RTOs and transmission owners, ruling on various issues and directing
      new compliance filings. This decision is subject to review and approval by
      the
      FERC. Briefs addressing the Initial Decision were filed on September 11, 2006
      and October 20, 2006. A final order could be issued by the FERC by the end
      of
      2006.





68











On
        January 31, 2005,
        certain PJM transmission owners made three filings with the FERC pursuant
        to a
        settlement agreement previously approved by the FERC. JCP&L, Met-Ed and
        Penelec were parties to that proceeding and joined in two of the filings.
        In the
        first filing, the settling transmission owners submitted a filing justifying
        continuation of their existing rate design within the PJM RTO. In the second
        filing, the settling transmission owners proposed a revised Schedule 12 to
        the
        PJM tariff designed to harmonize the rate treatment of new and existing
        transmission facilities. Interventions and protests were filed on February
        22,
        2005. In the third filing, Baltimore Gas and Electric Company and Pepco
        Holdings, Inc. requested a formula rate for transmission service provided
        within
        their respective zones. On May 31, 2005, the FERC issued an order on these
        cases. First, it set for hearing the existing rate design and indicated that
        it
        will issue a final order within six months. American Electric Power Company,
        Inc. filed in opposition proposing to create a "postage stamp" rate for high
        voltage transmission facilities across PJM. Second, the FERC approved the
        proposed Schedule 12 rate harmonization. Third, the FERC accepted the proposed
        formula rate, subject to refund and hearing procedures. On June 30, 2005,
        the
        settling PJM transmission owners filed a request for rehearing of the May
        31,
        2005 order. On March 20, 2006, a settlement was filed with FERC in the formula
        rate proceeding that generally accepts the companies' formula rate proposal.
        The
        FERC issued an order approving this settlement on April 19, 2006. Hearings
        in
        the PJM rate design case concluded in April 2006. On July 13, 2006, an Initial
        Decision was issued by the ALJ. The ALJ adopted the Trial Staff’s position that
        the cost of all PJM transmission facilities should be recovered through a
        postage stamp rate. ****** The
        ALJ recommended
        an April 1, 2006 effective date for this change in rate design. If the FERC
        accepts this recommendation, the transmission rate applicable to many load
        zones
        in PJM would increase. FirstEnergy believes that significant additional
        transmission revenues would have to be recovered from the JCP&L, Met-Ed and
        Penelec transmission zones within PJM. JCP&L, Met-Ed and Penelec as part of
        the Responsible Pricing Alliance, filed a brief addressing the Initial Decision
        on August 14, 2006 and September 5, 2006. The case will be reviewed by the
        FERC
        with a decision anticipated in the fourth quarter of 2006. ******
 
 On
        November 1, 2005,
        FES filed two power sales agreements for approval with the FERC. One power
        sales
        agreement provided for FES to provide the PLR requirements of the Ohio Companies
        at a price equal to the retail generation rates approved by the PUCO for
        a
        period of three years beginning January 1, 2006. The Ohio Companies will
        be
        relieved of their obligation to obtain PLR power requirements from FES if
        the
        Ohio CBP results in a lower price for retail customers. A similar power sales
        agreement between FES and Penn permits Penn to obtain its PLR power requirements
        from FES at a fixed price equal to the retail generation price during 2006.
 
 On
        December 29,
        2005, the FERC issued an order setting the two power sales agreements for
        hearing. The order criticized the Ohio CBP, and required FES to submit
        additional evidence in support of the reasonableness of the prices charged
        in
        the power sales agreements. A pre-hearing conference was held on January
        18,
        2006 to determine the hearing schedule in this case. Under the procedural
        schedule approved in this case, FES expected an initial decision to be issued
        in
        late January 2007. However, on July 14, 2006, the Chief Judge granted the
        joint
        motion of FES and the Trial Staff to appoint a settlement judge in this
        proceeding and the procedural schedule was suspended pending settlement
        discussions among the parties. A settlement conference was held on September
        5,
        2006. FES and the Ohio Companies, Penn, and the PUCO, along
        with other
        parties, reached an agreement to settle the case. The settlement was filed
        with
        the FERC on October 17, 2006, and was unopposed by the remaining parties,
        including the FERC Trial Staff. Initial comments to the settlement are due
        by
        November 6, 2006.
 The
          terms of the
          settlement provide for modification of both the Ohio and Penn power supply
          agreements with FES. Under the Ohio power supply agreement, separate rates
          are
          established for the Ohio Companies’ PLR requirements, special retail contracts
          requirements, wholesale contract requirements, and interruptible buy-through
          retail load requirements. For their PLR and special retail contract
          requirements, the Ohio Companies will pay FES no more than the lower of
          (i) the
          sum of the retail generation charge, the rate stabilization charge, the
          fuel
          recovery mechanism charge, and FES’ actual incremental fuel costs for such
          sales; or (ii) the wholesale price cap. Different wholesale price caps
          are
          imposed for PLR sales, special retail contracts, and wholesale contracts.
          The
          wholesale price for interruptible buy-through retail load requirements
          is
          limited to the actual spot price of power obtained by FES to provide this
          power.
          The Ohio Companies have recognized the estimated additional amount payable
          to
          FES for power supplied during the nine months ended September 30, 2006.
          The
          wholesale rate charged by FES under the Penn power supply agreement will
          be no
          greater than the generation component of charges for retail PLR load in
          Pennsylvania. The FERC is expected to act on this case by the end of the
          fourth
          quarter of 2006.
 As
        a result of
        Penn’s PLR competitive solicitation process approved by the PPUC, FES was
        selected as the winning bidder for a number of the tranches for individual
        customer classes. The balance of the tranches will be supplied by unaffiliated
        power suppliers. On October 2, 2006, FES filed an application with FERC under
        Section 205 of the Federal Power Act for authorization to make these affiliate
        sales to Penn. Interventions or protests were due on this filing on October
        23,
        2006. Penn was the only party to file an intervention in this proceeding.
        The
        FERC is expected to act on this filing on or before December 1,
        2006.
 
 On
        October 19, 2006,
        the FERC issued two final rules in connection with the Public Utility Holding
        Company Act of 2005 (PUHCA 2005). The final rules impose certain accounting,
        reporting and record-retention requirements for applicable holding companies
        and
        service companies, which includes FirstEnergy and certain of its
        subsidiaries.


69








***Environmental
      Matters***




FirstEnergy accrues environmental liabilities only when it concludes that it
      is
      probable that it has an obligation for such costs and can reasonably estimate
      the amount of such costs. Unasserted claims are reflected in FirstEnergy’s
      determination of environmental liabilities and are accrued in the period that
      they are both probable and reasonably estimable.




On December 1, 2005, FirstEnergy issued a comprehensive report to
      shareholders regarding air emissions regulations and an assessment of future
      risks and mitigation efforts. The report is available on FirstEnergy's Web
      site
      at www.firstenergycorp.com/environmental.





*Clean
      Air Act
      Compliance*




FirstEnergy is required to meet federally-approved SO 2 emissions
      regulations. Violations of such regulations can result in shutdown of the
      generating unit involved and/or civil or criminal penalties of up to $32,500
      for
      each day the unit is in violation. The EPA has an interim enforcement policy
      for
      SO 2 regulations in Ohio
      that allows for compliance based on a 30-day averaging period. FirstEnergy
      believes it is currently in compliance with this policy, but cannot predict
      what
      action the EPA may take in the future with respect to the interim enforcement
      policy.




The EPA
      Region
      5 issued a Finding of Violation and NOV to the Bay Shore Power Plant dated
      June
      15, 2006 alleging violations to various sections of the Clean Air Act. A meeting
      was held on August 8, 2006 to discuss the alleged violations with the EPA.
      FirstEnergy has disputed those alleged violations based on its Clean Air Act
      permit, the Ohio SIP and other information provided at the August 2006 meeting
      with the EPA. The EPA has several enforcement options (administrative compliance
      order, administrative penalty order, and/or judicial, civil or criminal action)
      and has indicated that such option may depend on the time needed to achieve
      and
      demonstrate compliance with the rules alleged to have been
      violated.




FirstEnergy complies with SO 2 reduction
      requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur
      fuel, generating more electricity from lower-emitting plants, and/or using
      emission allowances. NO X reductions required
      by the 1990 Amendments are being achieved through combustion controls and the
      generation of more electricity at lower-emitting plants. In September 1998,
      the
      EPA finalized regulations requiring additional NO X reductions at
      FirstEnergy's facilities. The EPA's NO X Transport Rule
      imposes uniform reductions of NO X emissions (an
      approximate 85% reduction in utility plant NO X emissions from
      projected 2007 emissions) across a region of nineteen states (including
      Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based
      on a conclusion that such NO X emissions are
      contributing significantly to ozone levels in the eastern United States.
      FirstEnergy believes its facilities are also complying with the NO X budgets established
      under SIPs through combustion controls and post-combustion controls, including
      Selective Catalytic Reduction and Selective Non-Catalytic Reduction systems,
      and/or using emission allowances.





*National
      Ambient
      Air Quality Standards*




In July 1997, the EPA promulgated changes in the NAAQS for ozone and fine
      particulate matter. In March 2005, the EPA finalized CAIR covering a total
      of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the
      District of Columbia based on proposed findings that air emissions from
      28 eastern states and the District of Columbia significantly contribute to
      non-attainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS
      in other states. CAIR provides each affected state until 2006 to develop
      implementing regulations to achieve additional reductions of NO X and SO 2 emissions in two
      phases (Phase I in 2009 for NO X ,
      2010 for
      SO 2 and Phase II in
      2015 for both NO X and SO 2 ).
      FirstEnergy's
      Michigan, Ohio and Pennsylvania fossil-fired generation facilities will be
      subject to caps on SO 2 and
      NO X emissions, whereas
      its New Jersey fossil-fired generation facility will be subject to a cap on
      NO X emissions only.
      According to the EPA, SO 2 emissions
      will be
      reduced by 45% (from 2003 levels) by 2010 across the states covered by the
      rule,
      with reductions reaching 73% (from 2003 levels) by 2015, capping SO 2 emissions in
      affected states to just 2.5 million tons annually. NO X emissions will be
      reduced by 53% (from 2003 levels) by 2009 across the states covered by the
      rule,
      with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional
      NO X cap of
      1.3 million tons annually. The future cost of compliance with these
      regulations may be substantial and will depend on how they are ultimately
      implemented by the states in which FirstEnergy operates affected facilities.





70








*Mercury
      Emissions*


In December 2000, the EPA announced it would proceed with the development
        of
        regulations regarding hazardous air pollutants from electric power plants,
        identifying mercury as the hazardous air pollutant of greatest concern. In
        March 2005, the EPA finalized CAMR, which provides for a cap-and-trade
        program to reduce mercury emissions from coal-fired power plants in two phases.
        Initially, mercury emissions will be capped nationally at 38 tons by 2010
        (as a "co-benefit" from implementation of SO 2 and NO X emission caps under
        the EPA's CAIR program). Phase II of the mercury cap-and-trade program will
        cap
        nationwide mercury emissions from coal-fired power plants at 15 tons per
        year by 2018. However, the final rules give states substantial discretion
        in
        developing rules to implement these programs. In addition, both CAIR and
        CAMR
        have been challenged in the United States Court of Appeals for the District
        of
        Columbia. FirstEnergy's future cost of compliance with these regulations
        may be
        substantial and will depend on how they are ultimately implemented by the
        states
        in which FirstEnergy operates affected facilities.




The model rules for both CAIR and CAMR contemplate an input-based methodology
      to
      allocate allowances to affected facilities. Under this approach, allowances
      would be allocated based on the amount of fuel consumed by the affected sources.
      FirstEnergy would prefer an output-based generation-neutral methodology in
      which
      allowances are allocated based on megawatts of power produced, since then,
      new
      and non-emitting generating facilities, including renewables and nuclear, would
      be entitled to their proportionate share of the allowances. Consequently,
      FirstEnergy will be disadvantaged if these model rules were implemented as
      proposed because FirstEnergy’s substantial reliance on non-emitting (largely
      nuclear) generation is not recognized under the input-based
      allocation.




Pennsylvania has proposed a new rule to regulate mercury emissions from
      coal-fired power plants that does not provide a cap and trade approach as in
      CAMR, but rather follows a command and control approach imposing emission limits
      on individual sources. If adopted as proposed, Pennsylvania’s mercury regulation
      would deprive FirstEnergy of mercury emission allowances that were to be
      allocated to the Mansfield Plant under CAMR and that would otherwise be
      available for achieving FirstEnergy system-wide compliance. The future cost
      of
      compliance with these regulations, if adopted and implemented as proposed,
      may
      be substantial.





*W.
      H. Sammis
      Plant*




In 1999 and 2000, the EPA issued NOV or Compliance Orders to nine utilities
      alleging violations of the Clean Air Act based on operation and maintenance
      of
      44 power plants, including the W. H. Sammis Plant, which was owned at that
      time
      by OE and Penn. In addition, the DOJ filed eight civil complaints against
      various investor-owned utilities, including a complaint against OE and Penn
      in
      the U.S. District Court for the Southern District of Ohio. These cases are
      referred to as New Source Review cases.


On March 18, 2005, OE and Penn announced that they had reached a settlement
      with
      the EPA, the DOJ and three states (Connecticut, New Jersey, and New York) that
      resolved all issues related to the W. H. Sammis Plant New Source Review
      litigation. This settlement agreement was approved by the Court on July 11,
      2005, and requires reductions of NO X and SO 2 emissions at the W.
      H. Sammis Plant and other coal-fired plants through the installation of
      pollution control devices and provides for stipulated penalties for failure
      to
      install and operate such pollution controls in accordance with that agreement.
      Consequently, if FirstEnergy fails to install such pollution control devices,
      for any reason, including, but not limited to, the failure of any third-party
      contractor to timely meet its delivery obligations for such devices, FirstEnergy
      could be exposed to penalties under the settlement agreement. Capital
      expenditures necessary to meet those requirements are currently estimated to
      be
      $1.5 billion ($400 million of which is expected to be spent in 2007 with the
      primary portion of the remaining $1.1 billion expected to be spent in 2008
      and
      2009). On August 26, 2005, FGCO entered into an agreement with Bechtel Power
      Corporation under which Bechtel will engineer, procure, and construct air
      quality control systems for the reduction of SO 2 emissions. FGCO
      also entered into an agreement with B&W on August 25, 2006 to supply flue
      gas desulfurization systems for the reduction of SO 2 emissions.
      Selective Catalytic Reduction (SCR) systems for the reduction of NOx emissions
      also are being installed at the W.H. Sammis Plant under a 1999 agreement with
      B&W.




The settlement agreement also requires OE and Penn to spend up to
      $25 million toward environmentally beneficial projects, which include wind
      energy purchased power agreements over a 20-year term. OE and Penn agreed to
      pay
      a civil penalty of $8.5 million. Results for the first quarter of 2005
      included the penalties paid by OE and Penn of $7.8 million and
      $0.7 million, respectively. OE and Penn also recognized liabilities in the
      first quarter of 2005 of $9.2 million and $0.8 million, respectively,
      for probable future cash contributions toward environmentally beneficial
      projects.





71








*Climate
      Change*




In December 1997, delegates to the United Nations' climate summit in Japan
      adopted an agreement, the Kyoto Protocol, to address global warming by reducing
      the amount of man-made GHG emitted by developed countries by 5.2% from 1990
      levels between 2008 and 2012. The United States signed the Kyoto Protocol in
      1998 but it failed to receive the two-thirds vote of the United States Senate
      required for ratification. However, the Bush administration has committed the
      United States to a voluntary climate change strategy to reduce domestic GHG
      intensity - the ratio of emissions to economic output - by 18% through 2012.
      The
      EPACT established a Committee on Climate Change Technology to coordinate federal
      climate change activities and promote the development and deployment of GHG
      reducing technologies.




FirstEnergy cannot currently estimate the financial impact of climate change
      policies, although the potential restrictions on CO 2 emissions could
      require significant capital and other expenditures. However, the CO 2 emissions per
      kilowatt-hour of electricity generated by FirstEnergy is lower than many
      regional competitors due to its diversified generation sources which include
      low
      or non-CO 2 emitting gas-fired
      and nuclear generators.





*Regulation
      of
      Hazardous Waste*




The Companies have been named as PRPs at waste disposal sites, which may require
      cleanup under the Comprehensive Environmental Response, Compensation, and
      Liability Act of 1980. Allegations of disposal of hazardous substances at
      historical sites and the liability involved are often unsubstantiated and
      subject to dispute; however, federal law provides that all PRPs for a particular
      site are liable on a joint and several basis. Therefore, environmental
      liabilities that are considered probable have been recognized on the
      Consolidated Balance Sheet as of September 30, 2006, based on estimates of
      the total costs of cleanup, the Companies' proportionate responsibility for
      such
      costs and the financial ability of other unaffiliated entities to pay. In
      addition, JCP&L has accrued liabilities for environmental remediation of
      former manufactured gas plants in New Jersey. Those costs are being recovered
      by
      JCP&L through a non-bypassable SBC. Total liabilities of approximately
      $73 million have been accrued through September 30, 2006.





See
      Note 1 0(B)
      to the
      consolidated financial statements for further details and a complete discussion
      of environmental matters.





***Other
      Legal Proceedings***




*Power
      Outages
      and Related Litigation*





On August 14, 2003, various states and parts of southern Canada experienced
      widespread power outages. The outages affected approximately 1.4 million
      customers in FirstEnergy's service area. The U.S. - Canada Power System Outage
      Task Force’s final report in April 2004 on the outages concluded, among other
      things, that the problems leading to the outages began in FirstEnergy’s Ohio
      service area. Specifically,
      the
      final report concluded, among other things, that the initiation of the
      August 14, 2003 power outages resulted from an alleged failure of both
      FirstEnergy and ECAR to assess and understand perceived inadequacies within
      the
      FirstEnergy system; inadequate situational awareness of the developing
      conditions; and a perceived failure to adequately manage tree growth in certain
      transmission rights of way. The Task Force also concluded that there was a
      failure of the interconnected grid's reliability organizations (MISO and PJM)
      to
      provide effective real-time diagnostic support. The final report is publicly
      available through the Department of Energy’s Web site (www.doe.gov). FirstEnergy
      believes that the final report does not provide a complete and comprehensive
      picture of the conditions that contributed to the August 14, 2003 power
      outages and that it does not adequately address the underlying causes of the
      outages. FirstEnergy remains convinced that the outages cannot be explained
      by
      events on any one utility's system. The final report contained 46
“recommendations to prevent or minimize the scope of future blackouts.”
Forty-five of those recommendations related to broad industry or policy matters
      while one, including subparts, related to activities the Task Force recommended
      be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct
      the
      causes of the August 14, 2003 power outages. FirstEnergy implemented
      several initiatives, both prior to and since the August 14, 2003 power
      outages, which were independently verified by NERC as complete in 2004 and
      were
      consistent with these and other recommendations and collectively enhance the
      reliability of its electric system. FirstEnergy’s implementation of these
      recommendations in 2004 included completion of the Task Force recommendations
      that were directed toward FirstEnergy. FirstEnergy is also proceeding with
      the
      implementation of the recommendations that were to be completed subsequent
      to
      2004 and will continue to periodically assess the FERC-ordered Reliability
      Study
      recommendations for forecasted 2009 system conditions, recognizing revised
      load
      forecasts and other changing system conditions which may impact the
      recommendations. Thus far, implementation of the recommendations has not
      required, nor is expected to require, substantial investment in new or material
      upgrades to existing equipment. The FERC or other applicable government agencies
      and reliability coordinators may, however, take a different view as to
      recommended enhancements or may recommend additional enhancements in the future
      as a result of adoption of mandatory reliability standards pursuant to the
      EPACT
      that could require additional material expenditures.





72




FirstEnergy companies also are defending six separate complaint cases before
      the
      PUCO relating to the August 14, 2003 power outages. Two cases were
      originally filed in Ohio State courts but were subsequently dismissed for lack
      of subject matter jurisdiction and further appeals were unsuccessful. In these
      cases the individual complainants—three in one case and four in the other—sought
      to represent others as part of a class action. The PUCO dismissed the class
      allegations, stating that its rules of practice do not provide for class action
      complaints. Three other pending PUCO complaint cases were filed by various
      insurance carriers either in their own name as subrogees or in the name of
      their
      insured. In each of these three cases, the carrier seeks reimbursement from
      various FirstEnergy companies (and, in one case, from PJM, MISO and American
      Electric Power Company, Inc., as well) for claims paid to insureds for damages
      allegedly arising as a result of the loss of power on August 14, 2003. The
      listed insureds in these cases, in many instances, are not customers of any
      FirstEnergy company. The sixth case involves the claim of a non-customer seeking
      reimbursement for losses incurred when its store was burglarized on
      August 14, 2003. That case has been dismissed. On
      March 7,
      2006, the PUCO issued a ruling, based on motions filed by the parties,
      applicable to all pending cases. Among its various rulings, the PUCO
      consolidated all of the pending outage cases for hearing; limited the litigation
      to service-related claims by customers of the Ohio operating companies;
      dismissed FirstEnergy as a defendant; ruled that the U.S.-Canada Power System
      Outage Task Force Report was not admissible into evidence; and gave the
      plaintiffs additional time to amend their complaints to otherwise comply with
      the PUCO’s underlying order. Also, most
      complainants, along with the FirstEnergy companies, filed applications for
      rehearing with the PUCO over various rulings contained in the March 7, 2006
      order. On April 26, 2006, the PUCO granted rehearing to allow the insurance
      company claimants, as insurers, to prosecute their claims in their name so
      long
      as they also identify the underlying insured entities and the Ohio utilities
      that provide their service. The PUCO denied all other motions for rehearing.
      The
      plaintiffs in each case have since filed an amended complaint and the named
      FirstEnergy companies have answered and also have filed a motion to dismiss
      each
      action. On September 27, 2006, the PUCO dismissed certain parties and claims
      and
      otherwise ordered the complaints to go forward to hearing. The cases have been
      set for hearing on October 16, 2007.




On October 10, 2006, various insurance carriers refiled a complaint in Cuyahoga
      County Common Pleas Court seeking reimbursement for claims paid to numerous
      insureds who allegedly suffered losses as a result of the August 14, 2003
      outage. All of the insureds appear to be non-customers. The plaintiff insurance
      companies are the same claimants in one of the pending PUCO cases. FirstEnergy,
      the Ohio Companies and Penn were served on October 27, 2006, and expect to
      seek summary dismissal of these cases based on the prior court rulings noted
      above. No estimate of potential liability is available for any of these
      cases.




FirstEnergy was also named, along with several other entities, in a complaint
      in
      New Jersey State Court. The allegations against FirstEnergy were based, in
      part,
      on an alleged failure to protect the citizens of Jersey City from an electrical
      power outage. None of FirstEnergy’s subsidiaries serve customers in Jersey City.
      A responsive pleading has been filed. On April 28, 2006, the Court granted
      FirstEnergy's motion to dismiss. The plaintiff has not appealed.




FirstEnergy is vigorously defending these actions, but cannot predict the
      outcome of any of these proceedings or whether any further regulatory
      proceedings or legal actions may be initiated against the Companies. Although
      unable to predict the impact of these proceedings, if FirstEnergy or its
      subsidiaries were ultimately determined to have legal liability in connection
      with these proceedings, it could have a material adverse effect on FirstEnergy's
      or its subsidiaries' financial condition, results of operations and cash
      flows.





*Nuclear
      Plant
      Matters*




On January 20, 2006, FENOC announced that it had entered into a deferred
      prosecution agreement with the U.S. Attorney’s Office for the Northern District
      of Ohio and the Environmental Crimes Section of the Environment and Natural
      Resources Division of the DOJ related to FENOC’s communications with the NRC
      during the fall of 2001 in connection with the reactor head issue at the
      Davis-Besse Nuclear Power Station. Under the agreement, which expires on
      December 31, 2006, the United States acknowledged FENOC’s extensive
      corrective actions at Davis-Besse, FENOC’s cooperation during investigations by
      the DOJ and the NRC, FENOC’s pledge of continued cooperation in any related
      criminal and administrative investigations and proceedings, FENOC’s
      acknowledgement of responsibility for the behavior of its employees, and its
      agreement to pay a monetary penalty. The DOJ will refrain from seeking an
      indictment or otherwise initiating criminal prosecution of FENOC for all conduct
      related to the statement of facts attached to the deferred prosecution
      agreement, as long as FENOC remains in compliance with the agreement, which
      FENOC fully intends to do. FENOC paid a monetary penalty of $28 million
      (not deductible for income tax purposes) which reduced FirstEnergy's earnings
      by
      $0.09 per common share in the fourth quarter of 2005.




On April 21, 2005, the NRC issued a NOV and proposed a $5.45 million
      civil penalty related to the degradation of the Davis-Besse reactor vessel
      head
      issue discussed above. FirstEnergy accrued $2 million for a potential fine
      prior to 2005 and accrued the remaining liability for the proposed fine during
      the first quarter of 2005. On September 14, 2005, FENOC filed its response
      to the NOV with the NRC. FENOC accepted full responsibility for the past failure
      to properly implement its boric acid corrosion control and corrective action
      programs. The NRC NOV indicated that the violations do not represent current
      licensee performance. FirstEnergy paid the penalty in the third quarter of
      2005.
      On January 23, 2006, FENOC supplemented its response to the NRC's NOV on
      the Davis-Besse head degradation to reflect the deferred prosecution agreement
      that FENOC had reached with the DOJ.





73







On August 12, 2004, the NRC notified FENOC that it would increase its
      regulatory oversight of the Perry Nuclear Power Plant as a result of problems
      with safety system equipment over the preceding two years and the licensee's
      failure to take prompt and corrective action. FENOC operates the Perry Nuclear
      Power Plant.




On April 4, 2005, the NRC held a public meeting to discuss FENOC’s
      performance at the Perry Nuclear Power Plant as identified in the NRC's annual
      assessment letter to FENOC. Similar public meetings are held with all nuclear
      power plant licensees following issuance by the NRC of their annual assessments.
      According to the NRC, overall the Perry Plant operated "in a manner that
      preserved public health and safety" even though it remained under heightened
      NRC
      oversight. During the public meeting and in the annual assessment, the NRC
      indicated that additional inspections will continue and that the plant must
      improve performance to be removed from the Multiple/Repetitive Degraded
      Cornerstone Column of the Action Matrix.




On September 28, 2005, the NRC sent a CAL to FENOC describing commitments
      that FENOC had made to improve the performance at the Perry Plant and stated
      that the CAL would remain open until substantial improvement was demonstrated.
      The CAL was anticipated as part of the NRC's Reactor Oversight Process. In
      the
      NRC's 2005 annual assessment letter dated March 2, 2006 and associated
      meetings to discuss the performance of Perry on March 14, 2006, the NRC
      again stated that the Perry Nuclear Power Plant continued to operate in a manner
      that "preserved public health and safety." However, the NRC also stated that
      increased levels of regulatory oversight would continue until sustained
      improvement in the performance of the facility was realized. If performance
      does
      not improve, the NRC has a range of options under the Reactor Oversight Process,
      from increased oversight to possible impact to the plant’s operating authority.
      Although FirstEnergy is unable to predict the impact of the ultimate disposition
      of this matter, it could have a material adverse effect on FirstEnergy's or
      its
      subsidiaries' financial condition, results of operations and cash
      flows.





*Other
      Legal
      Matters*




There are various lawsuits, claims (including claims for asbestos exposure)
      and
      proceedings related to FirstEnergy’s normal business operations pending against
      FirstEnergy and its subsidiaries. The other material items not otherwise
      discussed above are described below.




On October 20, 2004, FirstEnergy was notified by the SEC that the
      previously disclosed informal inquiry initiated by the SEC's Division of
      Enforcement in September 2003 relating to the restatements in August 2003 of
      previously reported results by FirstEnergy and the Ohio Companies, and the
      Davis-Besse extended outage, have become the subject of a formal order of
      investigation. The SEC's formal order of investigation also encompasses issues
      raised during the SEC's examination of FirstEnergy and the Companies under
      the
      now repealed PUHCA. Concurrent with this notification, FirstEnergy received
      a
      subpoena asking for background documents and documents related to the
      restatements and Davis-Besse issues. On December 30, 2004, FirstEnergy
      received a subpoena asking for documents relating to issues raised during the
      SEC's PUHCA examination. On August 24, 2005, additional information was
      requested regarding Davis-Besse related disclosures, which FirstEnergy has
      provided. FirstEnergy has cooperated fully with the informal inquiry and will
      continue to do so with the formal investigation.




On August 22, 2005, a class action complaint was filed against OE in
      Jefferson County, Ohio Common Pleas Court, seeking compensatory and punitive
      damages to be determined at trial based on claims of negligence and eight other
      tort counts alleging damages from W.H. Sammis Plant air emissions. The two
      named
      plaintiffs are also seeking injunctive relief to eliminate harmful emissions
      and
      repair property damage and the institution of a medical monitoring program
      for
      class members. On
      October 18,
      2006, the Ohio Supreme Court transferred this case to a Tuscarawas County Common
      Pleas Court judge due to concerns over potential class membership by the
      Jefferson County Common Pleas Court.




JCP&L's bargaining unit employees filed a grievance challenging JCP&L's
      2002 call-out procedure that required bargaining unit employees to respond
      to
      emergency power outages. On May 20, 2004, an arbitration panel concluded
      that the call-out procedure violated the parties' collective bargaining
      agreement. At the conclusion of the June 1, 2005 hearing, the arbitration
      panel decided not to hear testimony on damages and closed the proceedings.
      On
      September 9, 2005, the arbitration panel issued an opinion to award
      approximately $16 million to the bargaining unit employees. On February 6,
      2006, a federal district court granted a union motion to dismiss as premature
      a
      JCP&L appeal of the award filed on October 18, 2005. JCP&L intends
      to re-file an appeal again in federal district court once the damages associated
      with this case are identified at an individual employee level. JCP&L
      recognized a liability for the potential $16 million award in
      2005.





74







The City of Huron filed a complaint against OE with the PUCO challenging the
      ability of electric distribution utilities to collect transition charges from
      a
      customer of a newly-formed municipal electric utility. The complaint was filed
      on May 28, 2003, and OE timely filed its response on June 30, 2003. In
      a related filing, the Ohio Companies filed for approval with the PUCO of a
      tariff that would specifically allow the collection of transition charges from
      customers of municipal electric utilities formed after 1998. Both filings were
      consolidated for hearing and decision. An adverse ruling could negatively affect
      full recovery of transition charges by the utility. Hearings on the matter
      were
      held in August 2005. Initial briefs from all parties were filed on
      September 22, 2005 and reply briefs were filed on October 14, 2005. On
      May 10, 2006, the PUCO issued its Opinion and Order dismissing the City’s
      complaint and approving the related tariffs, thus affirming OE’s entitlement to
      recovery of its transition charges. The City of Huron
      filed an application for rehearing of the PUCO’s decision on June 9, 2006
      and OE filed a memorandum in opposition to that application on June 19,
      2006. The PUCO denied the City’s application for rehearing on June 28, 2006. The
      City of Huron has taken no further action and the period for filing an appeal
      has expired.




If it were ultimately determined that FirstEnergy or its subsidiaries have
      legal
      liability or are otherwise made subject to liability based on the above matters,
      it could have a material adverse effect on FirstEnergy’s or its subsidiaries’
financial condition, results of operations and cash flows.




See Note 10(C) to the consolidated financial statements for further details
      and a complete discussion of these and other legal proceedings.





**NEW
      ACCOUNTING STANDARDS AND INTERPRETATIONS**





*SAB
                108 -
                “Considering the Effects of Prior Year Misstatements when Quantifying
                Misstatements in Current Year Financial
                Statements”*





In
      September 2006, the SEC issued SAB 108, which provides interpretive guidance
      on
      how registrants should quantify financial statement misstatements. There is
      currently diversity in practice, with the two commonly used methods to quantify
      misstatements being the “rollover” method (which primarily focuses on the income
      statement impact of misstatements) and the “iron curtain” method (which focuses
      on the balance sheet impact). SAB 108 requires registrants to use a dual
      approach whereby both of these methods are considered in evaluating the
      materiality of financial statement errors. Prior materiality assessments will
      need to be reconsidered using both the rollover and iron curtain methods. This
      guidance will be effective for FirstEnergy in the fourth quarter of 2006.
      FirstEnergy does
      not expect this
      Statement to have a material impact on its financial statements.





*EITF
                06-5
                - “Accounting for Purchases of Life Insurance-Determining the Amount
                That
                Could Be Realized in Accordance with FASB Technical Bulletin No.
                85-4,
                Accounting for Purchases of Life
                Insurance”*





In September 2006, the EITF reached a consensus on Issue 06-5 concluding that
      a
      policyholder should consider any additional amounts included in the contractual
      terms of the policy in determining the amount that could be realized under
      the
      insurance contract. Contractual limitations should be considered when
      determining the realizable amounts. Amounts that are recoverable by the
      policyholder at the discretion of the insurance company should be excluded
      from
      the amount that could be realized. Recoverable amounts in periods beyond one
      year from the surrender of the policy should be discounted in accordance with
      APB Opinion No. 21, “Interest on Receivables and Payables.” Consensus was
      also reached that a policyholder should determine the amount that could be
      realized under the insurance contract assuming the surrender of an
      individual-life by individual-life policy (or certificate by certificate in
      a
      group policy). Any amount that would ultimately be realized by the policyholder
      upon the assumed surrender of the final policy (or final certificate) should
      be
      included in the amount that could be realized under the insurance contract.
      The
      EITF also concluded that a policyholder should not discount the cash surrender
      value component of the amount that could be realized when contractual
      restrictions on the ability to surrender a policy exist. However, if the
      contractual limitations prescribe that the cash surrender value component of
      the
      amount that could be realized is a fixed amount, then the amount that could
      be
      realized should be discounted in accordance with APB Opinion No. 21. This
      Issue is effective for fiscal years beginning after December 15, 2006.
      FirstEnergy does not expect this EITF to have a material impact on its financial
      statements.





*SFAS
      157 - “Fair
      Value Measurements”*





In September 2006, the FASB issued SFAS 157 that establishes how companies
      should measure fair value when they are required to use a fair value measure
      for
      recognition or disclosure purposes under GAAP. This Statement addresses the
      need
      for increased consistency and comparability in fair value measurements and
      for
      expanded disclosures about fair value measurements. The key changes to current
      practice are: (1) the definition of fair value which focuses on an exit price
      rather than entry price; (2) the methods used to measure fair value such as
      emphasis that fair value is a market-based measurement, not an entity-specific
      measurement, as well as the inclusion of an adjustment for risk, restrictions
      and credit standing; and (3) the expanded disclosures about fair value
      measurements.





75











This Statement is effective for financial statements issued for fiscal years
      beginning after November 15, 2007, and interim periods within those years.
      FirstEnergy is currently evaluating the impact of this Statement on its
      financial statements.





*SFAS
                158 -
                “Employers’ Accounting for Defined Benefit Pension and Other
                Postretirement Plans-an amendment of FASB Statements No. 87, 88,
                106, and
                132(R)”*





In September 2006, the FASB issued SFAS 158, which requires companies to
      recognize a net liability or asset to report the overfunded or underfunded
      status of their defined benefit pension and other postretirement benefit plans
      on their balance sheets and recognize changes in funded status in the year
      in
      which the changes occur through other comprehensive income. The funded status
      to
      be measured is the difference between plan assets at fair value and the benefit
      obligation. This Statement requires that gains and losses and prior service
      costs or credits, net of tax, that arise during the period be recognized as
      a
      component of other comprehensive income and not as components of net periodic
      benefit cost. Additional information should also be disclosed in the notes
      to
      the financial statements about certain effects on net periodic benefit cost
      for
      the next fiscal year that arise from delayed recognition of the gains or losses,
      prior service costs or credits, and transition asset or obligation. Upon the
      initial application of this Statement and subsequently, an employer should
      continue to apply the provisions in Statements 87, 88 and 106 in measuring
      plan
      assets and benefit obligations as of the date of its statement of financial
      position and in determining the amount of net periodic benefit cost. This
      Statement is effective for FirstEnergy as of December 31, 2006. Based upon
      the December 31, 2005 measurement date, the estimated balance sheet impacts
      of adopting this Statement are a reduction in total assets of $0.4 billion,
      an increase in liabilities of $0.6 billion and a decrease in equity of
      $1 billion, before recognition of any related regulatory assets that may be
      appropriate under the circumstances.





*FSP
      FIN 46(R)-6
      - “Determining the Variability to Be Considered in Applying FASB interpretation
      No. 46(R)”*





In
      April 2006, the
      FASB issued FSP FIN 46(R)-6 that addresses how a reporting enterprise should
      determine the variability to be considered in applying FASB interpretation
      No.
      46 (revised December 2003). FirstEnergy adopted FIN 46(R) in the first quarter
      of 2004, consolidating VIE’s when FirstEnergy or one of its subsidiaries is
      determined to be the VIE’s primary beneficiary. The variability that is
      considered in applying interpretation 46(R) affects the determination of (a)
      whether the entity is a VIE; (b) which interests are variable interests in
      the
      entity; and (c) which party, if any, is the primary beneficiary of the VIE.
      This
      FSP states that the variability to be considered shall be based on an analysis
      of the design of the entity, involving two steps:





Step
                1:
            Analyze
                the
                nature of the risks in the entityStep
                2:
            Determine
                the
                purpose(s) for which the entity was created and determine the variability
                the entity is designed to create and pass along to its interest
                holders.





After
      determining
      the variability to consider, the reporting enterprise can determine which
      interests are designed to absorb that variability. The guidance in this FSP
      is
      applied prospectively to all entities (including newly created entities) with
      which that enterprise first becomes involved and to all entities previously
      required to be analyzed under interpretation 46(R) when a reconsideration event
      has occurred after July 1, 2006. FirstEnergy does not expect this Statement
      to have a material impact on its financial statements.





*FIN
      48 -
“Accounting for Uncertainty in Income Taxes - an interpretation of FASB
      Statement No. 109.”*





In
      June 2006, the
      FASB issued FIN 48 which clarifies the accounting for uncertainty in income
      taxes recognized in an enterprise’s financial statements in accordance with FASB
      Statement No. 109, “Accounting for Income Taxes.” This interpretation prescribes
      a recognition threshold and measurement attribute for the financial statement
      recognition and measurement of a tax position taken or expected to be taken
      on a
      tax return. This interpretation also provides guidance on derecognition,
      classification, interest, penalties, accounting in interim periods, disclosure
      and transition. The evaluation of a tax position in accordance with this
      interpretation will be a two-step process. The first step will determine if
      it
      is more likely than not that a tax position will be sustained upon examination
      and should therefore be recognized. The second step will measure a tax position
      that meets the more likely than not recognition threshold to determine the
      amount of benefit to recognize in the financial statements. This interpretation
      is effective for fiscal years beginning after December 15, 2006. FirstEnergy
      is
      currently evaluating the impact of this Statement.





76




**OHIO
                  EDISON
                  COMPANY****CONSOLIDATED
                  STATEMENTS OF INCOME AND COMPREHENSIVE
                  INCOME****(Unaudited)****Three
                  Months Ended**
              
              **Nine
                  Months Ended****September
                  30,**
              
              **September
                  30,****2006**
              
              **2005**
              
              **2006**
              
              **2005****STATEMENTS
                  OF INCOME**
              
              ***(In
                  thousands)*****REVENUES**
              
              $
              673,673
              
              $
              825,790
              
              $
              1,832,968
              
              $
              2,268,760**EXPENSES:**Fuel
              
              
              2,954
              
              
              15,158
              
              
              8,726
              
              
              39,080Purchased
                  power
              
              
              395,560
              
              
              229,561
              
              
              971,613
              
              
              703,658Nuclear
                  operating costs
              
              
              44,995
              
              
              76,254
              
              
              129,585
              
              
              264,514Other
                  operating costs
              
              
              108,362
              
              
              114,762
              
              
              290,776
              
              
              293,530Provision
                  for
                  depreciation
              
              
              18,399
              
              
              30,169
              
              
              53,962
              
              
              87,875Amortization
                  of regulatory assets
              
              
              49,717
              
              
              126,439
              
              
              147,022
              
              
              347,880Deferral
                  of
                  new regulatory assets
              
              
              (44,962
              )
              
              (43,929
              )
              
              (123,285
              )
              
              (107,750
              )General
                  taxes
              
              
              47,826
              
              
              51,945
              
              
              137,652
              
              
              146,066Total
                  expenses
              
              
              622,851
              
              
              600,359
              
              
              1,616,051
              
              
              1,774,853**OPERATING
                  INCOME**
              
              
              50,822
              
              
              225,431
              
              
              216,917
              
              
              493,907**OTHER
                  INCOME (EXPENSE):**Investment
                  income
              
              
              32,993
              
              
              25,260
              
              
              98,853
              
              
              68,349Miscellaneous
                  income (expense)
              
              
              1,639
              
              
              368
              
              
              835
              
              
              (23,529
              )Interest
                  expense
              
              
              (24,597
              )
              
              (17,182
              )
              
              (60,195
              )
              
              (56,787
              )Capitalized
                  interest
              
              
              698
              
              
              3,014
              
              
              1,832
              
              
              8,255Subsidiary's
                  preferred stock dividend requirements
              
              
              (156
              )
              
              (156
              )
              
              (467
              )
              
              (1,534
              )Total
                  other
                  income (expense)
              
              
              10,577
              
              
              11,304
              
              
              40,858
              
              
              (5,246
              )**INCOME
                  BEFORE INCOME TAXES**
              
              
              61,399
              
              
              236,735
              
              
              257,775
              
              
              488,661**INCOME
                  TAXES**
              
              
              17,902
              
              
              105,337
              
              
              91,239
              
              
              253,410**NET
                  INCOME**
              
              
              43,497
              
              
              131,398
              
              
              166,536
              
              
              235,251**PREFERRED
                  STOCK DIVIDEND REQUIREMENTS****AND
                  REDEMPTION PREMIUM**
              
              
              51
              
              
              659
              
              
              4,297
              
              
              1,976**EARNINGS
                  ON COMMON STOCK**
              
              $
              43,446
              
              $
              130,739
              
              $
              162,239
              
              $
              233,275**STATEMENTS
                  OF COMPREHENSIVE INCOME****NET
                  INCOME**
              
              $
              43,497
              
              $
              131,398
              
              $
              166,536
              
              $
              235,251**OTHER
                  COMPREHENSIVE INCOME (LOSS):**Unrealized
                  gain (loss) on available for sale securities
              
              
              3,795
              
              
              (3,402
              )
              
              5,467
              
              
              (19,079
              )Income
                  tax
                  expense (benefit) related to othercomprehensive
                  income
              
              
              1,369
              
              
              (2,043
              )
              
              1,972
              
              
              (7,713
              )Other
                  comprehensive income (loss), net of tax
              
              
              2,426
              
              
              (1,359
              )
              
              3,495
              
              
              (11,366
              )**TOTAL
                  COMPREHENSIVE INCOME**
              
              $
              45,923
              
              $
              130,039
              
              $
              170,031
              
              $
              223,885The
                  preceding
                  Notes to Consolidated Financial Statements as they relate to Ohio
                  Edison
                  Company are an integral part of thesestatements.
   77
  **OHIO
                    EDISON COMPANY****CONSOLIDATED
                    BALANCE SHEETS****(Unaudited)****September
                    30,**
                
                
                **December
                    31,****2006**
                
                
                **2005****(In
                    thousands)****ASSETS****CURRENT
                    ASSETS:**Cash
                    and cash
                    equivalents
                
                $
                703
                
                
                $
                929Receivables-Customers
                    (less accumulated provisions of $15,017,000 and $7,619,000,
                    respectively,for
                    uncollectible accounts)
                
                
                255,173
                
                
                
                290,887Associated
                    companies
                
                
                190,516
                
                
                
                187,072Other
                    (less
                    accumulated provisions of $1,058,000 and $4,000,
                    respectively,for
                    uncollectible accounts)
                
                
                21,399
                
                
                
                15,327Notes
                    receivable from associated companies
                
                
                471,393
                
                
                
                536,629Prepayments
                    and other
                
                
                19,053
                
                
                
                93,129958,237
                
                
                
                1,123,973**UTILITY
                    PLANT:**In
                    service
                
                
                2,599,266
                
                
                
                2,526,851Less
                    -
                    Accumulated provision for depreciation
                
                
                1,005,404
                
                
                
                984,4631,593,862
                
                
                
                1,542,388Construction
                    work in progress
                
                
                48,397
                
                
                
                58,7851,642,259
                
                
                
                1,601,173**OTHER
                    PROPERTY AND INVESTMENTS:**Long-term
                    notes receivable from associated companies
                
                
                1,675,813
                
                
                
                1,758,776Investment
                    in
                    lease obligation bonds
                
                
                310,077
                
                
                
                325,729Nuclear
                    plant
                    decommissioning trusts
                
                
                111,325
                
                
                
                103,854Other
                
                
                39,734
                
                
                
                44,2102,136,949
                
                
                
                2,232,569**DEFERRED
                    CHARGES AND OTHER ASSETS:**Regulatory
                    assets
                
                
                746,001
                
                
                
                774,983Prepaid
                    pension costs
                
                
                229,316
                
                
                
                224,813Property
                    taxes
                
                
                52,897
                
                
                
                52,875Unamortized
                    sale and leaseback costs
                
                
                51,386
                
                
                
                55,139Other
                
                
                27,463
                
                
                
                31,7521,107,063
                
                
                
                1,139,562$
                5,844,508
                
                
                $
                6,097,277**LIABILITIES
                    AND CAPITALIZATION****CURRENT
                    LIABILITIES:**Currently
                    payable long-term debt
                
                $
                226,191
                
                
                $
                280,255Short-term
                    borrowings-Associated
                    companies
                
                
                1,608
                
                
                
                57,715Other
                
                
                22,097
                
                
                
                143,585Accounts
                    payable-Associated
                    companies
                
                
                146,370
                
                
                
                172,511Other
                
                
                10,811
                
                
                
                9,607Accrued
                    taxes
                
                
                136,044
                
                
                
                163,870Accrued
                    interest
                
                
                21,172
                
                
                
                8,333Other
                
                
                100,742
                
                
                
                61,726665,035
                
                
                
                897,602**CAPITALIZATION:**Common
                    stockholder's equity-Common
                    stock,
                    without par value, authorized 175,000,000 shares -
                
                
                1,796,560
                
                
                
                2,297,25380
                    and 100
                    shares outstanding, respectivelyAccumulated
                    other comprehensive income
                
                
                7,589
                
                
                
                4,094Retained
                    earnings
                
                
                290,880
                
                
                
                200,844Total
                    common
                    stockholder's equity
                
                
                2,095,029
                
                
                
                2,502,191Preferred
                    stock not subject to mandatory redemption
                
                
                -
                
                
                
                60,965Preferred
                    stock of consolidated subsidiary not subject to mandatory
                    redemption
                
                
                14,105
                
                
                
                14,105Long-term
                    debt
                    and other long-term obligations
                
                
                1,526,833
                
                
                
                1,019,6423,635,967
                
                
                
                3,596,903**NONCURRENT
                    LIABILITIES:**Accumulated
                    deferred income taxes
                
                
                736,396
                
                
                
                769,031Accumulated
                    deferred investment tax credits
                
                
                21,419
                
                
                
                24,081Asset
                    retirement obligations
                
                
                86,893
                
                
                
                82,527Retirement
                    benefits
                
                
                296,634
                
                
                
                291,051Deferred
                    revenues - electric service programs
                
                
                96,718
                
                
                
                121,693Other
                
                
                305,446
                
                
                
                314,3891,543,506
                
                
                
                1,602,772**COMMITMENTS
                    AND CONTINGENCIES (Note 10)**$
                5,844,508
                
                
                $
                6,097,277The
                    preceding
                    Notes to Consolidated Financial Statements as they relate to
                    Ohio Edison
                    Company are an integral part of these balancesheets.
   78
  **OHIO
                    EDISON COMPANY****CONSOLIDATED
                    STATEMENTS OF CASH FLOWS****(Unaudited)****Nine
                    Months Ended****September
                    30,****2006**
                
                **2005*****(In
                    thousands)*****CASH
                    FLOWS FROM OPERATING ACTIVITIES:**Net
                    income
                
                $
                166,536
                
                $
                235,251Adjustments
                    to
                    reconcile net income to net cash from operating activities
                    -Provision
                    for
                    depreciation
                
                
                53,962
                
                
                87,875Amortization
                    of regulatory assets
                
                
                147,022
                
                
                347,880Deferral
                    of
                    new regulatory assets
                
                
                (123,285
                )
                
                (107,750
                )Nuclear
                    fuel
                    and lease amortization
                
                
                728
                
                
                30,530Amortization
                    of lease costs
                
                
                28,600
                
                
                30,011Deferred
                    income taxes and investment tax credits, net
                
                
                (27,850
                )
                
                (22,929
                )Accrued
                    compensation and retirement benefits
                
                
                2,985
                
                
                10,261Decrease
                    (increase) in operating assets -Receivables
                
                
                26,198
                
                
                110,460Materials
                    and
                    supplies
                
                
                -
                
                
                (2,538
                )Prepayments
                    and other current assets
                
                
                (4,172
                )
                
                (4,232
                )Increase
                    (decrease) in operating liabilities -Accounts
                    payable
                
                
                (24,937
                )
                
                (105,234
                )Accrued
                    taxes
                
                
                (27,826
                )
                
                60,443Accrued
                    interest
                
                
                12,839
                
                
                1,667Electric
                    service prepayment programs
                
                
                (24,975
                )
                
                127,586Other
                
                
                1,842
                
                
                1,372Net
                    cash
                    provided from operating activities
                
                
                207,667
                
                
                800,653**CASH
                    FLOWS FROM FINANCING ACTIVITIES:**New
                    Financing
                    -Long-term
                    debt
                
                
                592,763
                
                
                146,450Short-term
                    borrowings, net
                
                
                -
                
                
                65,696Redemptions
                    and Repayments -Common
                    stock
                
                
                (500,000
                )
                
                -Preferred
                    stock
                
                
                (63,893
                )
                
                (37,750
                )Long-term
                    debt
                
                
                (138,085
                )
                
                (278,327
                )Short-term
                    borrowings, net
                
                
                (177,595
                )
                
                -Dividend
                    Payments -Common
                    stock
                
                
                (73,000
                )
                
                (241,000
                )Preferred
                    stock
                
                
                (1,369
                )
                
                (1,976
                )Net
                    cash used
                    for financing activities
                
                
                (361,179
                )
                
                (346,907
                )**CASH
                    FLOWS FROM INVESTING ACTIVITIES:**Property
                    additions
                
                
                (94,278
                )
                
                (190,804
                )Proceeds
                    from
                    nuclear decommissioning trust fund sales
                
                
                34,655
                
                
                196,235Investments
                    in
                    nuclear decommissioning trust funds
                
                
                (36,038
                )
                
                (219,890
                )Loan
                    repayments from (loans to) associated companies, net
                
                
                148,199
                
                
                (258,561
                )Cash
                    investments
                
                
                93,900
                
                
                13,372Other
                
                
                6,848
                
                
                5,572Net
                    cash
                    provided from (used for) investing activities
                
                
                153,286
                
                
                (454,076
                )Net
                    decrease
                    in cash and cash equivalents
                
                
                (226
                )
                
                (330
                )Cash
                    and cash
                    equivalents at beginning of period
                
                
                929
                
                
                1,230Cash
                    and cash
                    equivalents at end of period
                
                $
                703
                
                $
                900The
                    preceding
                    Notes to Consolidated Financial Statements as they relate to
                    Ohio Edison
                    Company are an integral partof
                    these
                    statements.
  
 79








***Report
      of Independent Registered Public Accounting Firm***





























To
      the Stockholder
      and Board of


Directors
      of Ohio
      Edison Company:





We
      have reviewed the
      accompanying consolidated balance sheet of Ohio Edison Company and its
      subsidiaries as of September 30, 2006, and the related consolidated statements
      of income and comprehensive income for each of the three-month and nine-month
      periods ended September 30, 2006 and 2005 and the consolidated statements of
      cash flows for the nine-month periods ended September 30, 2006 and 2005. These
      interim financial statements are the responsibility of the Company’s
      management.





We
      conducted our
      review in accordance with the standards of the Public Company Accounting
      Oversight Board (United States). A review of interim financial information
      consists principally of applying analytical procedures and making inquiries
      of
      persons responsible for financial and accounting matters. It is substantially
      less in scope than an audit conducted in accordance with the standards of the
      Public Company Accounting Oversight Board, the objective of which is the
      expression of an opinion regarding the financial statements taken as a whole.
      Accordingly, we do not express such an opinion.





Based
      on our review,
      we are not aware of any material modifications that should be made to the
      accompanying consolidated interim financial statements for them to be in
      conformity with accounting principles generally accepted in the United States
      of
      America.





We
      have previously
      audited, in accordance with the standards of the Public Company Accounting
      Oversight Board (United States), the consolidated balance sheet as of December
      31, 2005, and the related consolidated statements of income, capitalization,
      common stockholder’s equity, preferred stock, cash flows and taxes for the year
      then ended (not presented herein), and in our report [which contained references
      to the Company’s change in its method of accounting for asset retirement
      obligations as of January 1, 2003 and conditional asset retirement obligations
      as of December 31, 2005 as discussed in Note 2(G) and Note 11 to those
      consolidated financial statements] dated February 27, 2006, we expressed an
      unqualified opinion on those consolidated financial statements. In our opinion,
      the information set forth in the accompanying consolidated balance sheet as
      of
      December 31, 2005, is fairly stated in all material respects in relation to
      the
      consolidated balance sheet from which it has been derived.





PricewaterhouseCoopers
                LLP
              Cleveland,
                Ohio
              October
                31,
                2006











80





**OHIO
      EDISON
      COMPANY**





**MANAGEMENT’S
      DISCUSSION AND ANALYSIS OF**


**RESULTS
      OF
      OPERATIONS AND FINANCIAL CONDITION**








OE
      is a wholly owned
      electric utility subsidiary of FirstEnergy. OE and its wholly owned subsidiary,
      Penn, conduct business in portions of Ohio and Pennsylvania, providing regulated
      electric distribution services. Penn’s rate restructuring plan and its
      associated transition charge revenue recovery was completed in 2005. The OE
      Companies also provide generation services to those customers electing to retain
      the OE Companies as their power supplier. Power supply requirements of the
      OE
      Companies are provided by FES - an affiliated
      company.





**FirstEnergy
      Intra-System Generation Asset Transfers**




In 2005, the Ohio Companies and Penn entered into certain agreements
      implementing a series of intra-system generation asset transfers that were
      completed in the fourth quarter of 2005. The asset transfers resulted in the
      respective undivided ownership interests of the Ohio Companies and Penn in
      FirstEnergy’s nuclear and non-nuclear generation assets being owned by NGC and
      FGCO, respectively. The generating plant interests transferred did not include
      OE's leasehold interests in certain of the plants that are currently subject
      to
      sale and leaseback arrangements with non-affiliates.




On October 24, 2005, the OE Companies completed the intra-system transfer
      of non-nuclear generation assets to FGCO. Prior to the transfer, FGCO, as lessee
      under a Master Facility Lease with the Ohio Companies and Penn, leased, operated
      and maintained the non-nuclear generation assets that it now owns. The asset
      transfers were consummated pursuant to FGCO's purchase option under the Master
      Facility Lease.




On December 16, 2005, the OE Companies completed the intra-system transfer
      of their ownership interests in the nuclear generation assets to NGC through
      an
      asset spin-off in the form of a dividend. FENOC continues to operate and
      maintain the nuclear generation assets.




These transactions were undertaken pursuant to the Ohio Companies’ and Penn’s
      restructuring plans that were approved by the PUCO and the PPUC, respectively,
      under applicable Ohio and Pennsylvania electric utility restructuring
      legislation. Consistent with the restructuring plans, generation assets that
      had
      been owned by the Ohio Companies and Penn were required to be separated from
      the
      regulated delivery business of those companies through transfer to a separate
      corporate entity. The transactions essentially completed the divestitures
      contemplated by the restructuring plans by transferring the ownership interests
      to NGC and FGCO without impacting the operation of the plants.




The transfers affect the OE Companies' comparative earnings results with
      reductions in both revenues and expenses. Revenues are reduced due to the
      termination of certain arrangements with FES, under which the OE Companies
      previously sold their nuclear-generated KWH to FES and leased their non-nuclear
      generation assets to FGCO, a subsidiary of FES. Their expenses are lower due
      to
      the nuclear fuel and operating costs assumed by NGC as well as depreciation
      and
      property tax expenses assumed by FGCO and NGC related to the transferred
      generating assets. With respect to OE's retained leasehold interests in the
      Perry Plant and Beaver Valley Unit 2, OE has continued the
      nuclear-generated KWH sales arrangement with FES for the associated output
      and
      continues to be obligated on the applicable portion of expenses related to
      those
      interests. In addition, the OE Companies receive interest income on associated
      company notes receivable from the transfer of their generation net assets.
      FES
      continues to provide OE’s PLR requirements under revised purchased power
      arrangements covering the three-year period beginning January 1, 2006 and
      Penn’s during the remainder of 2006 (see Outlook - Regulatory
      Matters).








81





The effects on the OE Companies' results of operations in the third quarter
      and
      nine months ended September 30, 2006 as compared to the same periods of
      2005 from the generation asset transfers (also reflecting OE's retained
      leasehold interests discussed above) are summarized in the following table:





**Intra-System
                Generation Asset Transfers****Income
                Statement Effects**
            
            **Three
                Months**
            
            
            **Nine
                Months****Increase
                (Decrease)**
            
            ***(In
                millions)***Revenues:Non-nuclear
                generating units rent
            (a)
            $
            (44)
            
            
            $
            (133)Nuclear-generated
                KWH sales
            (b)
            
            (86)
            
            
            
            (217)Total
                -
                Revenues Effect
            
            
            (130)
            
            
            
            (350)Expenses:Fuel
                costs -
                nuclear
            (c)
            
            (12)
            
            
            
            (30)Nuclear
                operating costs
            (c)
            
            (33)
            
            
            
            (122)Provision
                for
                depreciation
            (d)
            
            (15)
            
            
            
            (43)General
                taxes
            (e)
            
            (3)
            
            
            
            (9)Total
                -
                Expenses Effect
            
            
            (63)
            
            
            
            (204)Operating
                Income Effect
            
            
            (67)
            
            
            
            (146)Other
                Income:Interest
                income from notes receivable
            (f)
            
            14
            
            
            
            44Nuclear
                decommissioning trust earnings
            (g)
            
            (5)
            
            
            
            (11)Capitalized
                Interest
            (h)
            
            (3)
            
            
            
            (7)Total
                - Other
                Income Effect
            
            
            6
            
            
            
            26Income
                taxes
            (i)
            
            (25)
            
            
            
            (49)Net
                Income
                Effect
            
            $
            (36)
            
            
            $
            (71)(a)
                Elimination of non-nuclear generation assets lease to
                FGCO.(b)
                Reduction
                of nuclear-generated wholesale KWH sales to FES.(c)
                Reduction
                of nuclear fuel and operating costs.(d)
                Reduction
                of depreciation expense and asset retirement obligation accretion
                related
                to generation assets.(e)
                Reduction
                of property tax expense on generation assets.(f)
                Interest
                income on associated company notes receivable from the transfer of
                generation net assets.(g)
                Reduction
                of earnings on nuclear decommissioning trusts.(h)
                Reduction
                of allowance for borrowed funds used during construction on nuclear
                capital expenditures.(i)
                Income tax
                effect of the above adjustments.





**Results
      of Operations**


Earnings
        on common
        stock in the third quarter of 2006 decreased to $43 million from $131
        million in the third quarter of 2005. In the first nine months of 2006, earnings
        on common stock decreased to $162 million from $233 million in the same
        period of 2005. The change in earnings in both periods reflected the effects
        of
        the generation asset transfer shown in the table above. Expenses during the
        third quarter of 2006 included $25 million of costs associated with the
        proposed FERC settlement (see Note 11) applicable to the first half of 2006.
        Earnings in the first nine months of 2005 were reduced by additional income
        taxes of $36 million from the implementation of Ohio tax legislation changes
        and
        charges related to an $8.5 million civil penalty payable to the DOJ and
        $10 million for environmental projects in connection with the Sammis Plant
        settlement (see Outlook — Environmental Matters).


*Revenues*





Revenues
      decreased
      by $152 million or 18.4% in the third quarter of 2006 compared with the same
      period in 2005, primarily due to the generation asset transfer impact summarized
      in the table above. Excluding the effects of the asset transfer, revenues in
      the
      third quarter of 2006 decreased $22 million, primarily due to decreases of
      $68
      million and $127 million in wholesale sales and distribution revenues,
      respectively, partially offset by increases in retail generation revenues of
      $149 million and reduced customer shopping incentives of $24 million.





In
      the first nine
      months of 2006 compared with the same period in 2005, revenues decreased by
      $436
      million or 19.2%, primarily from the generation asset transfer impact summarized
      in the table above. Excluding the effects of the asset transfer, revenues in
      the
      first nine months of 2006 decreased $86 million, primarily due to decreases
      of
      $198 million and $337 million in wholesale sales and distribution revenues,
      respectively, partially offset by increases in retail generation revenues of
      $381 million and reduced customer shopping incentives of $62
      million.





82











The
      lower wholesale
      revenues in both periods of 2006 primarily resulted from the termination of
      a
      non-affiliated wholesale sales agreement and the December 2005 cessation of
      the
      MSG sales arrangements under OE’s transition plan. OE had been required to
      provide the MSG to non-affiliated alternative suppliers.





Changes
      in electric
      generation KWH sales and revenues
      in the
      third quarter and first nine months of 2006 from the corresponding periods
      of
      2005 are summarized in the following table.





**Changes
                in Generation KWH Sales**
            
            **Three
                Months**
            
            **Nine
                Months****Increase
                (Decrease)**Electric
                Generation:Retail
            
            
            14.9
            %
            
            13.3
            %Wholesale
            
            
            (85.8)
            %
            
            (83.9)
            %**Net
                Decrease in Generation Sales**
            
            
            **(32.7)**
            **%**
            
            **(30.7)**
            **%**





**Changes
                  in Generation Revenues**
              
              **Three
                  Months**
              
              **Nine
                  Months****Increase
                  (Decrease)**
              
              ***(In
                  millions)***Retail
                  Generation:Residential
              
              $
              59
              
              $
              143Commercial
              
              
              46
              
              
              116Industrial
              
              
              44
              
              
              122Total
                  Retail
                  Generation
              
              
              149
              
              
              381Wholesale*
              
              
              (68
              )
              
              (198
              )**Net
                  Increase in Generation Revenues**
              
              **$**
              **81**
              
              $
              183*
                  Excludes
                  impact of generation asset transfers related to nuclear-generated
                  KWH
                  sales.





Increased
      retail
      generation revenues for the third quarter of 2006 (as shown in the table above)
      resulted from higher KWH sales and higher unit prices. The increase in
      generation KWH sales primarily resulted from decreased customer shopping, as
      the
      percentage of generation services provided by alternative suppliers to total
      sales delivered in OE's service area decreased by: residential - 12.4 percentage
      points; commercial - 13.0 percentage points; and industrial - 10.9 percentage
      points. The decrease in shopping resulted from certain alternative energy
      suppliers terminating their supply arrangements with OE’s shopping customers in
      the fourth quarter of 2005. Higher unit prices for generation reflected the
      rate
      stabilization charge and the fuel recovery rider that both became effective
      in
      the first quarter of 2006 under provisions of the RSP and RCP.





Retail
      generation
      revenues increased in the first nine months of 2006 compared to the same period
      of 2005 for the reasons described above. The increase in generation KWH sales
      primarily resulted from a decrease in customer shopping, as the percentage
      of
      generation services provided by alternative suppliers to total sales delivered
      in OE's service area decreased by: residential - 10.6 percentage points;
      commercial - 12.2 percentage points; and industrial - 10.5 percentage points.
      Higher unit prices for generation reflected the impact of the RSP and RCP
      described above.





Changes
      in
      distribution KWH deliveries and revenues in the
      third quarter and first nine months of 2006 from the corresponding periods
      of
      2005 are summarized in the following table.





**Changes
                in Distribution KWH Deliveries**
            
            **Three
                Months**
            
            **Nine
                Months****Increase
                (Decrease)**Distribution
                Deliveries:Residential
            
            
            (4.2)
            %
            
            (3.9)
            %Commercial
            
            
            (1.4)
            %
            
            (1.5)
            %Industrial
            
            
            0.3
            %
            
            0.4
            %**Net
                Decrease in Distribution Deliveries**
            
            
            **(1.8)**
            **%**
            
            **(1.7)**
            **%**








83








**Changes
                in Distribution Revenues**
            
            **Three
                Months**
            
            **Nine
                Months****Increase
                (Decrease)**
            
            ***(In
                millions)***Residential
            
            $
            (60)
            
            $
            (148)Commercial
            
            
            (37)
            
            
            (102)Industrial
            
            
            (30)
            
            
            (87)**Net
                Decrease in Distribution Revenues**
            
            
            **(127)**
            
            **$**
            **(337)**




Lower
      distribution
      revenues shown in the table above for the third quarter and first nine months
      of
      2006 reflect lower composite prices and reduced KWH deliveries to residential
      and commercial customers. The lower unit prices in both periods resulted from
      the completion of the generation-related transition cost recovery under the
      OE
      Companies’ respective rate restructuring  plans
      in 2005,
      partially offset by increased transmission rates to recover MISO costs beginning
      in 2006 (see Outlook - Regulatory Matters). Lower KWH deliveries to residential
      and commercial customers reflected the impact of milder weather conditions
      in
      the third quarter and first nine months of 2006, compared to the same periods
      of
      2005. KWH deliveries to industrial customers increased slightly in both periods
      due to the recovering steel industry in the OE Companies’ service
      territory.





Under
      the Ohio
      transition plan, OE provided incentives to customers to encourage switching
      to
      alternative energy providers, which reduced OE’s revenues by $24 million in the
      third quarter of 2005 and $62 million in the first nine months of 2005. These
      revenue reductions, which were deferred for future recovery and did not affect
      earnings, ceased in 2006. The deferred shopping incentives (Extended RTC) are
      now being recovered under the RCP (see Outlook - Regulatory
      Matters).





*Expenses*


Total
        expenses
        increased by $22 million in the third quarter of 2006 and decreased by
        $159 million in the first nine months of 2006 from the same periods of
        2005. The change in both periods was impacted by the effects of the
        generation asset transfers shown in the table above. Excluding the asset
        transfer effects, the following table presents changes from the prior year
        by
        expense category:


**Expenses
                - Changes**
            
            **Three
                Months**
            
            **Nine
                Months****Increase
                (Decrease)**
            
            ***(In
                millions)***Purchased
                power costs
            
            $
            166
            
            $
            268Nuclear
                operating costs
            
            
            2
            
            
            (12
            )Other
                operating costs
            
            
            (7
            )
            
            (3
            )Provision
                for
                depreciation
            
            
            3
            
            
            9Amortization
                of regulatory assets
            
            
            (77
            )
            
            (201
            )Deferral
                of
                new regulatory assets
            
            
            (1
            )
            
            (16
            )General
                taxes
            
            
            (2
            )
            
            -**Net
                increase in expenses**
            
            **$**
            **84**
            
            
            **45**





I ncreased
      purchased
      power costs in the third quarter and first nine months of 2006 reflected higher
      unit prices associated with the new power supply agreement with FES, partially
      offset by a decrease in KWH purchased to meet the lower net generation sales
      requirements. Excluding the effects of the generation asset transfers, the
      lower
      nuclear operating costs in the first nine months of 2006 for OE’s nuclear
      leasehold interests were primarily due to the absence in 2006 of both the Beaver
      Valley Unit 2 refueling outage in 2005 and the Perry Nuclear Power Plant
      scheduled refueling outage (including an unplanned extension) that was completed
      on May 6, 2005. The decrease in other operating costs during the third quarter
      and the first nine months of 2006 was primarily due to lower associated company
      (FES) transmission expenses as a result of alternative energy suppliers
      terminating their supply arrangements with OE’s shopping customers in the fourth
      quarter of 2005 and lower employee benefit expenses. These decreases in the
      first nine months of 2006 were partially offset by increases in transmission
      expenses related to MISO Day 2 operations that began on April 1,
      2005.





Excluding
      the
      effects of the generation asset transfers, higher depreciation expense in the
      third quarter and first nine months of 2006 reflected capital additions
      subsequent to the third quarter of 2005. Lower amortization of regulatory assets
      in both periods was due to the completion of the generation-related transition
      cost amortization under the OE Companies' respective transition plans, partially
      offset by the amortization of deferred MISO costs being recovered in 2006.
      The
      higher deferrals of new regulatory assets in the third quarter and first nine
      months of 2006 primarily resulted from the deferral of fuel costs ($21 million
      and $45 million, respectively) and distribution costs ($18 million and $58
      million, respectively) under the RCP, partially offset by lower MISO cost
      deferrals ($13 million and $23 million, respectively) and the decrease in
      shopping incentive deferrals ($25 million and $64 million, respectively) which
      ceased in 2006 under the Ohio transition plan. The deferral of interest on
      the
      unamortized shopping incentive balances continues under the RCP.





84








*Other
      Income
      (Expense)*





Other
      income
      decreased $1 million in the third quarter of 2006 as compared with the same
      period of 2005, reflecting the effects of the generation asset transfers.
      Excluding the effects of the generation asset transfers, the $8 million decrease
      in the third quarter of 2006 was primarily due to an additional $10 million
      of
      interest expense from OE’s June 2006 issuance of $600 million of long-term debt.
      As discussed below under Capital Resources and Liquidity, OE primarily used
      the
      debt proceeds to repurchase $500 million of its common stock from FirstEnergy.
      This represents a part of FirstEnergy’s 2006 refinancing strategy to obtain
      additional holding company financing flexibility by using the OE common stock
      repurchase proceeds to redeem holding company debt and to capitalize its
      regulated utility subsidiaries more appropriately from a regulatory context.





Other
      income
      increased $46 million in the first nine months of 2006 as compared with the
      same
      period of 2005, primarily due to the effects of the generation asset transfers.
      Excluding the effects of the generation asset transfers, the $20 million
      increase in the first nine months of 2006 is primarily due to the absence in
      2006 of the 2005 charges of $8.5 million for a civil penalty payable to the
      DOJ
      and $10 million for environmental projects in connection with the Sammis
      New Source Review settlement (see Outlook - Environmental
      Matters) partially offset by a $3 million increase in interest expense. The
      interest expense increase reflected the effect of the June 2006 long-term debt
      issuance discussed above, and was partially offset by the impact of other debt
      redemptions subsequent to the third quarter of 2005.





*Income
      Taxes*


Income
        taxes
        decreased $87 million in the third quarter of 2006 and $162  million
        in the first nine months of 2006 compared with the same periods of 2005.
        Excluding the effects of the generation asset transfer, income taxes decreased
        $63 million in the third quarter of 2006 and $113 million
        in
        the first nine months of 2006. The
        decreases in
        both periods was mainly due to decreases in taxable income, partially offset
        by
        a reduction in the tax rates due to the continuing phase-out of the income-based
        Ohio franchise tax. The income taxes decrease in the
        first nine months of 2006 also reflected the absence in 2006 of a $36
        million
        write-off of net deferred tax benefits in the second quarter of 2005, resulting
        from the new Ohio tax legislation in 2005.


**Capital
      Resources and Liquidity**





OE’s
      cash
      requirements for the remainder of 2006 for operating expenses, construction
      expenditures and scheduled debt maturities are expected to be met with cash
      from
      operations and short-term credit arrangements. OE repurchased $500 million
      of
      common stock from FirstEnergy and redeemed $64 million of preferred stock
      (including redemption premiums) in July 2006 with proceeds of senior notes
      issued in June 2006. Available borrowing capacity under credit facilities will
      be used to manage working capital requirements.





*Changes
      in Cash
      Position*





OE
      had $703,000 of
      cash and cash equivalents as of September 30, 2006 compared with $929,000 as
      of
      December 31, 2005. The major sources for changes in these balances are
      summarized below.





*Cash
      Flows From
      Operating Activities*





Cash
      provided from
      operating activities during the first nine months of 2006, compared with the
      corresponding period in 2005, was as follows:





**Nine
                Months Ended****September
                30,****Operating
                Cash Flows**
            
            
            **2006**
            
            **2005****(*****In
                millions)***Cash
                earnings(1)
            
            
            $
            224
            
            $
            603Working
                capital and other
            
            
            
            (16
            )
            
            198Net
                cash
                provided from operating activities
            
            
            $
            208
            
            $
            801


(1)  Cash
      earnings are a
      non-GAAP measure (see reconciliation below).





85








Cash
      earnings (in
      the table above) are not a measure of performance calculated in accordance
      with
      GAAP. OE believes that cash earnings is a useful financial measure because
      it
      provides investors and management with an additional means of evaluating its
      cash-based operating performance. Generally,
      a
      non-GAAP financial measure is a numerical measure of a company’s historical or
      future financial performance, financial position, or cash flows that either
      excludes or includes amounts, or is subject to adjustment that has the effect
      of
      excluding or including amounts, that are not normally excluded or included
      in
      the most directly comparable measure calculated and presented in accordance
      with
      GAAP. In addition, cash earnings (non-GAAP) are not defined under GAAP.
      Management believes presenting this non-GAAP measure provides useful information
      to investors in assessing OE’s operating performance from a cash perspective
      without the effects of material unusual economic events. OE’s management
      frequently references these non-GAAP financial measures in its decision-making,
      using them to facilitate historical and ongoing performance comparisons as
      well
      as comparisons to the performance of peer companies. These non-GAAP measures
      should be considered in addition to, and not as a substitute for, their most
      directly comparable financial measures prepared in accordance with
      GAAP.





**Nine
                Months Ended****September
                30,****Reconciliation
                of Cash Earnings**
            
            **2006**
            
            **2005****(*****In
                millions)***Net
                income
                (GAAP)
            
            $
            167
            
            $
            235Non-cash
                charges (credits):Provision
                for
                depreciation
            
            
            54
            
            
            88Amortization
                of regulatory assets
            
            
            147
            
            
            348Deferral
                of
                new regulatory assets
            
            
            (123)
            
            
            (108)Nuclear
                fuel
                and capital lease amortization
            
            
            1
            
            
            31Amortization
                of electric service obligation
            
            
            (25)
            
            
            (8)Amortization
                of lease costs
            
            
            28
            
            
            30Deferred
                income taxes and investment tax credits, net
            
            
            (28)
            
            
            (23)Accrued
                compensation and retirement benefits
            
            
            3
            
            
            10Cash
                earnings
                (Non-GAAP)
            
            $
            224
            
            $
            603





Net
        cash provided
        from operating activities decreased $593 million in the first nine months
        of 2006, compared with the same period in 2005, due to a $379 million
        decrease in cash earnings as described above under “Results of Operations” and a
        $214 million decrease from changes in working capital. The decrease in working
        capital primarily reflects the absence in 2006 of $136 million in funds received
        under the Energy for Education program in 2005 and changes in accrued taxes
        of
        $88 million and accounts receivable of $84 million, partially offset by
        changes in accounts payable of $80 million.


*Cash
      Flows From
      Financing Activities*




Net
      cash used for
      financing activities increased by $14 million in the first nine months of
      2006 from the same period last year. The increase in funds used for financing
      activities primarily resulted from a $500 million repurchase of common stock,
      partially offset by a $317 million decrease in net preferred stock and debt
      redemptions and a $168 million decrease in common stock dividend payments to
      FirstEnergy.





OE
      had approximately
      $472 million of cash and temporary cash investments (which include short-term
      notes receivable from associated companies) and $24 million of short-term
      indebtedness as of September 30, 2006. OE has authorization from the PUCO to
      incur short-term debt of up to $500 million, which is available through the
      bank facility and the utility money pool described below. Penn has authorization
      from the FERC to incur short-term debt up to its charter limit of
      $44 million as of September 30, 2006, and also has access to the bank
      facility and the utility money pool.





OES
      Capital is a
      wholly owned subsidiary of OE whose borrowings are secured by customer accounts
      receivable purchased from OE. OES Capital can borrow up to $170 million
      under a receivables financing arrangement. As a separate legal entity with
      separate creditors, OES Capital would have to satisfy its obligations to
      creditors before any of its remaining assets could be made available to OE.
      As
      of September 30, 2006, the facility was not drawn.





Penn
      Power Funding
      LLC (Penn Funding), a wholly owned subsidiary of Penn, is a limited liability
      company whose borrowings are secured by customer accounts receivable purchased
      from Penn. Penn Funding can borrow up to $25 million under a receivables
      financing arrangement which expires July 28,
      2007 .
      As a separate legal entity with separate creditors, Penn Funding would have
      to
      satisfy its obligations to creditors before any of its remaining assets could
      be
      made available to Penn. As
      of September 30,
      2006, the facility was drawn for $19 million.





86





As
      of September 30,
      2006, OE and Penn had the aggregate capability to issue approximately
      $592 million of additional FMB on the basis of property additions and
      retired bonds under the terms of their respective mortgage indentures. The
      issuance of FMB by OE is also subject to provisions of its senior note indenture
      generally limiting the incurrence of additional secured debt, subject to certain
      exceptions that would permit, among other things, the issuance of secured debt
      (including FMB) (i) supporting pollution control notes or similar obligations,
      or (ii) as an extension, renewal or replacement of previously outstanding
      secured debt. In addition, OE is permitted under the indenture to incur
      additional secured debt not otherwise permitted by a specified exception of
      up
      to $655 million as of September 30, 2006. Based upon applicable earnings
      coverage tests in its charter, Penn could issue a total of $136 million of
      preferred stock (assuming no additional debt was issued) as of
      September 30, 2006. As
      a result of OE
      redeeming all of its outstanding preferred stock on July 7, 2006, the applicable
      earnings coverage test is inoperable for OE. In the event that OE issues
      preferred stock in the future, the applicable earnings coverage test will govern
      the amount of additional preferred stock that OE may issue.





As
      of September 30,
      2006, OE had approximately $400 million of capacity remaining unused under
      its existing shelf registration for unsecured debt securities.





On
      August 24,
      2006,  FirstEnergy,
      OE,
      Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as Borrowers, entered
      into a new $2.75 billion five-year revolving credit facility which replaced
      the
      prior $2 billion credit facility. FirstEnergy may request an increase in the
      total commitments available under the new facility up to a maximum of $3.25
      billion. Commitments under the new facility are available until August 24,
      2011, unless the lenders agree, at the request of the Borrowers, to two
      additional one-year extensions. Generally, borrowings under the facility must
      be
      repaid within 364 days. Available amounts for each Borrower are subject to
      a
      specified sub-limit, as well as applicable regulatory and other limitations.
      OE's borrowing limit under the facility is $500 million and Penn’s is
      $50 million, subject in each case to applicable regulatory
      approvals.





Under
      the revolving
      credit facility, borrowers may request the issuance of LOCs expiring up to
      one
      year from the date of issuance. The stated amount of outstanding LOCs will
      count
      against total commitments available under the facility and against the
      applicable borrower’s borrowing sub-limit. Total unused borrowing capability
      under the credit facility and accounts receivable financing facilities totaled
      $726 million as of September 30, 2006.





The
      revolving credit
      facility contains financial covenants requiring each borrower to maintain a
      consolidated debt to total capitalization ratio of no more than 65%, measured
      at the end
      of each fiscal quarter. As
      of September 30,
      2006, debt to total capitalization as defined under the revolving credit
      facility was 46% for OE and 33% for Penn .





The
      revolving credit
      facility does not contain any provisions that either restricts the ability
      of OE
      and Penn to borrow or accelerate repayment of outstanding advances as a result
      of any change in credit ratings. Pricing is defined in “pricing grids”, whereby
      the cost of funds borrowed under the facility is related to OE’s and Penn’s
      credit ratings.





OE and Penn have the ability to borrow from their regulated affiliates and
      FirstEnergy to meet their short-term working capital requirements. FESC
      administers this money pool and tracks surplus funds of FirstEnergy and its
      regulated subsidiaries. Companies receiving a loan under the money pool
      agreements must repay the principal amount, together with accrued interest,
      within 364 days of borrowing the funds. The rate of interest is the same for
      each company receiving a loan from the pool and is based on the average cost
      of
      funds available through the pool. The average interest rate for borrowings
      in
      the first nine months of 2006 was 5.09%.





OE’s access to the capital markets and the costs of financing are influenced by
      the ratings of its securities. The ratings outlook from S&P on all
      securities is stable. The ratings outlook from Moody's and Fitch on all
      securities is positive.




On April 3, 2006, pollution control notes that were formerly obligations of
      OE
      and Penn were refinanced and became obligations of FGCO and NGC. The proceeds
      from the refinancings were used to repay a portion of FGCO’s and NGC’s
      associated company notes payable to Penn and OE. With those repayments, OE
      redeemed $74.8 million and Penn redeemed $6.95 million of pollution
      control notes having variable interest rates.





On
      June 26,
      2006, OE issued $600 million of unsecured senior notes, comprised of $250
      million of 6.4% notes due 2016 and $350 million of 6.875% notes due 2036. The
      net proceeds from this offering were used in July 2006 to repurchase $500
      million of OE common stock from FirstEnergy, redeem approximately $61 million
      of
      its preferred stock and to reduce short-term borrowings.





87








*Cash
      Flows From
      Investing Activities*





Net
      cash provided
      from investing activities was $153 million in the first nine months of 2006
      compared to $454 million used for investing activities in the first nine months
      of 2005. The change resulted primarily from a $407 million increase in loan
      repayments from associated companies and a $97 million decrease in property
      additions, which reflects the impact of the generation asset transfers and
      $78 million from liquidating investments (restrictions on short-term
      investments expired for an escrow fund and a mortgage indenture deposit).





In
      the last quarter
      of 2006, capital requirements for property additions and capital leases are
      expected to be approximately $20 million. OE has additional requirements of
      approximately $2 million to meet requirements for maturing long-term debt during
      the remainder of 2006. These cash requirements are expected to be satisfied
      from
      a combination of internal cash and short-term credit arrangements. OE’s
      capital
      spending for the period 2006-2010 is expected to be approximately $630 million,
      of which approximately $114 million applies to 2006.





**Off-Balance
      Sheet Arrangements**





Obligations
      not
      included on OE’s Consolidated Balance Sheets primarily consist of sale and
      leaseback arrangements involving Perry Unit 1 and Beaver Valley Unit 2. The
      present value of these operating lease commitments, net of trust investments,
      was $655 million as of September 30, 2006.





**Equity
      Price Risk**





Included
      in OE’s
      nuclear decommissioning trust investments are marketable equity securities
      carried at their market value of approximately $73 million and $67 million
      as of
      September 30, 2006 and December 31, 2005, respectively. A hypothetical
      10% decrease in prices quoted by stock exchanges would result in a $7 million
      reduction in fair value as of September 30, 2006. Changes in the fair value
      of
      these investments are recorded in OCI unless recognized as a result of a sale
      or
      recognized as regulatory assets or liabilities.





**Outlook**





The
      electric
      industry continues to transition to a more competitive environment and all
      of
      the OE Companies’ customers can select alternative energy suppliers. The OE
      Companies continue to deliver power to residential homes and businesses through
      their existing distribution system, which remains regulated. Customer rates
      have
      been restructured into separate components to support customer choice. In Ohio
      and Pennsylvania, the OE Companies have a continuing responsibility to provide
      power to those customers not choosing to receive power from an alternative
      energy supplier subject to certain limits.





*Regulatory
      Matters*





Regulatory
      assets
      and liabilities are costs which have been authorized by the PUCO, the PPUC
      and
      the FERC for recovery from, or credit to, customers in future periods or for
      which authorization is probable. Without the probability of such authorization,
      costs currently recorded as regulatory assets and liabilities would have been
      charged or creditied to income as incurred. All regulatory assets are expected
      to be recovered under the provisions of OE’s transition plan. OE‘s regulatory
      assets were $746 million and $775 million as of September 30,
      2006 and December 31, 2005, respectively. Penn had net regulatory liabilities
      of
      $64 million and $59 million as of September 30, 2006 and December 31, 2005,
      respectively, which are included in Other Noncurrent Liabilities on the
      Consolidated Balance Sheets as of September 30, 2006 and December 31,
      2005.





88








On
      October 21, 2003,
      the Ohio Companies filed their RSP case with the PUCO. On August 5, 2004, the
      Ohio Companies accepted the RSP as modified and approved by the PUCO in an
      August 4, 2004 Entry on Rehearing, subject to a CBP. The RSP was intended to
      establish generation service rates beginning January 1, 2006, in response to
      the
      PUCO’s concerns about price and supply uncertainty following the end of the Ohio
      Companies' transition plan market development period. In October 2004, the
      OCC
      and NOAC filed appeals with the Supreme Court of Ohio to overturn the original
      June 9, 2004 PUCO order in the proceeding as well as the associated entries
      on
      rehearing. On May 3, 2006, the Supreme Court of Ohio issued an opinion affirming
      the PUCO's order with respect to the approval of the rate stabilization charge,
      approval of the shopping credits, the granting of interest on shopping credit
      incentive deferral amounts, and approval of the Ohio Companies’ financial
      separation plan. It remanded back to the PUCO the matter of ensuring the
      availability of sufficient means for customer participation in the competitive
      marketplace. The RSP contained a provision that permitted the Ohio Companies
      to
      withdraw and terminate the RSP in the event that the PUCO, or the Supreme Court
      of Ohio, rejected all or part of the RSP. In such event, the Ohio Companies
      have
      30 days from the final order or decision to provide notice of termination.
      On
      July 20, 2006 the Ohio Companies filed with the PUCO a Request to Initiate
      a
      Proceeding on Remand. In their Request, the Ohio Companies provided notice
      of
      termination to those provisions of the RSP subject to termination, subject
      to
      being withdrawn, and also set forth a framework for addressing the Supreme
      Court
      of Ohio’s findings on customer participation, requesting the PUCO to initiate a
      proceeding to consider the Ohio Companies’ proposal. If the PUCO approves a
      resolution to the issues raised by the Supreme Court of Ohio that is acceptable
      to the Ohio Companies, the Ohio Companies’ termination will be withdrawn and
      considered to be null and void. Separately, the OCC and NOAC also submitted
      to
      the PUCO on July 20, 2006 a conceptual proposal dealing with the issue raised
      by
      the Supreme Court of Ohio. On July 26, 2006, the PUCO issued an Entry
      acknowledging the July 20, 2006 filings of the Ohio Companies and the OCC and
      NOAC, and giving the Ohio Companies 45 days to file a plan in a new docket
      to
      address the Court’s concern. On September 19, 2006, the PUCO issued an
      Entry granting the Ohio Companies’ motion for extension of time to file the
      remand proposal. The Ohio Companies filed their RSP Remand CBP on
      September 29, 2006. No further proceedings have been scheduled at this
      time.




The Ohio Companies filed an application and stipulation with the PUCO on
      September 9, 2005 seeking approval of the RCP, a supplement to the RSP. On
      November 4, 2005, the Ohio Companies filed a supplemental stipulation with
      the
      PUCO, which constituted an additional component of the RCP filed on September
      9,
      2005. Major provisions of the RCP include:





●
            Maintaining
                the existing level of base distribution rates through December 31,
                2008 for OE;●
            Deferring
                and
                capitalizing for future recovery (over a 25-year period) with carrying
                charges certain distribution costs to be incurred by all of the Ohio
                Companies during the period January 1, 2006 through December 31,
                2008, not to exceed $150 million in each of the three
                years;●
            Adjusting
                the
                RTC and extended RTC recovery periods and rate levels so that full
                recovery of authorized costs will occur as of December 31, 2008 for
                OE;●
            Reducing
                the
                deferred shopping incentive balances as of January 1, 2006 by up to
                $75 million for OE by accelerating the application of its accumulated
                cost of removal regulatory liability; and●
            Recovering
                increased fuel costs (compared to a 2002 baseline) of up to $75 million,
                $77 million, and $79 million, in 2006, 2007, and 2008,
                respectively, from all OE and TE distribution and transmission customers
                through a fuel recovery mechanism. The Ohio Companies may defer and
                capitalize (for recovery over a 25-year period) increased fuel costs
                above
                the amount collected through the fuel recovery mechanism.





The following table provides OE’s estimated net amortization of regulatory
      transition costs and deferred shopping incentives (including associated carrying
      charges) under the RCP for the period 2006 through 2008:





**Amortization****Period**
            
            **Amortization*****(In
                millions)***2006
            
            $
            1732007
            
            
            1802008
            
            
            207**Total
                Amortization**
            
            **$**
            **560**








89







On January 4, 2006, the PUCO approved, with modifications, the Ohio Companies’
RCP to supplement the RSP to provide customers with more certain rate levels
      than otherwise available under the RSP during the plan period. On
      January 10, 2006, the Ohio Companies filed a Motion for Clarification of
      the PUCO order approving the RCP. The Ohio Companies sought clarity on issues
      related to distribution deferrals, including requirements of the review process,
      timing for recognizing certain deferrals and definitions of the types of
      qualified expenditures. The Ohio Companies also sought confirmation that the
      list of deferrable distribution expenditures originally included in the revised
      stipulation fall within the PUCO order definition of qualified expenditures.
      On
      January 25, 2006, the PUCO issued an Entry on Rehearing granting in part,
      and denying in part, the Ohio Companies’ previous requests and clarifying issues
      referred to above. The PUCO granted the Ohio Companies’ requests to:





·
            Recognize
                fuel
                and distribution deferrals commencing January 1,
                2006;·
            Recognize
                distribution deferrals on a monthly basis prior to review by the
                PUCO
                Staff;·
            Clarify
                that
                the types of distribution expenditures included in the Supplemental
                Stipulation may be deferred; and·
            Clarify
                that
                distribution expenditures do not have to be “accelerated” in order to be
                deferred.




The PUCO approved the Ohio Companies’ methodology for determining distribution
      deferral amounts, but denied the Motion in that the PUCO Staff must verify
      the
      level of distribution expenditures contained in current rates, as opposed to
      simply accepting the amounts contained in the Ohio Companies’ Motion. On
      February 3, 2006, several other parties filed applications for rehearing on
      the PUCO's January 4, 2006 Order. The Ohio Companies responded to the
      applications for rehearing on February 13, 2006. In an Entry on Rehearing
      issued by the PUCO on March 1, 2006, all motions for rehearing were denied.
      Certain of these parties have subsequently filed notices of appeal with the
      Supreme Court of Ohio alleging various errors made by the PUCO in its order
      approving the RCP. The Ohio Companies’ Motion to Intervene in the appeals was
      granted by the Supreme Court on June 8, 2006. The Appellants’ Merit Briefs were
      filed at the Supreme Court on July 5, 2006. The Appellees include the PUCO
      and the Ohio Companies. The Appellees’ Merit Briefs were filed on
      August 24, 2006 and the Appellants’ Reply Briefs were filed on
      September 21, 2006. The OCC filed an amicus brief on August 4, 2006,
      which the Ohio Companies moved to strike as improperly filed. The Supreme Court
      denied the Ohio Companies’ motion on October 18, 2006.


On December 30, 2004, OE filed with the PUCO two applications related to
        the recovery of transmission and ancillary service related costs. The first
        application sought recovery of these costs beginning January 1, 2006. OE
        requested that these costs be recovered through a rider that would be effective
        on January 1, 2006 and adjusted each July 1 thereafter. The parties
        reached a settlement agreement that was approved by the PUCO on August 31,
        2005. The incremental transmission and ancillary service revenues recovered
        from
        January 1 through June 30, 2006 were approximately
        $31
        million. That amount included the
        recovery of a portion of the 2005 deferred MISO expenses as described below.
        On
        April 27, 2006, OE filed the annual update rider to determine revenues
        ($70 million) from July 2006 through June
        2007. The filed rider went into effect on July 1,
        2006.


The
      second
      application sought authority to defer costs associated with transmission and
      ancillary service related costs incurred during the period October 1, 2003
      through December 31, 2005. On May 18, 2005, the PUCO granted the
      accounting authority for the Ohio Companies to defer incremental transmission
      and ancillary service-related charges incurred as a participant in MISO, but
      only for those costs incurred during the period December 30, 2004 through
      December 31, 2005. Permission to defer costs incurred prior to
      December 30, 2004 was denied. The PUCO also authorized the Ohio Companies
      to accrue carrying charges on the deferred balances. On August 31, 2005,
      the OCC appealed the PUCO's decision. On
      January 20,
      2006, the OCC sought rehearing of the PUCO’s approval of the recovery of
      deferred costs through the rider during the period January 1, 2006 through
      June 30, 2006. The PUCO denied the OCC's application on February 6,
      2006. On March 23, 2006, the OCC appealed the PUCO's order to the Ohio
      Supreme Court. On March 27, 2006, the OCC filed a motion to consolidate
      this appeal with the deferral appeals discussed above and to postpone oral
      arguments in the deferral appeal until after all briefs are filed in this most
      recent appeal of the rider recovery mechanism. On
      March 20, 2006,
      the Ohio Supreme Court, on its own motion, consolidated the OCC's appeal of
      the
      Ohio Companies' case with a similar case involving Dayton Power & Light
      Company. Oral arguments were heard on May 10, 2006. The Ohio Companies are
      awaiting a final ruling from the Ohio Supreme Court, which is expected before
      the end of 2006.







90







Under Pennsylvania's electric competition law, Penn is required to secure
      generation supply for customers who do not choose alternative suppliers for
      their electricity. On October 11, 2005, Penn filed a plan with the PPUC to
      secure electricity supply for its customers at set rates following the end
      of
      its transition period on December 31, 2006. Penn recommended that the RFP
      process cover the period January 1, 2007 through May 31, 2008.
      Hearings before the PPUC were held on January 10, 2006 with main briefs
      filed on January 27, 2006 and reply briefs filed on February 3, 2006.
      On February 16, 2006, the ALJ issued a Recommended Decision to adopt Penn's
      RFP process with modifications. On April 20, 2006, the PPUC approved the
      Recommended Decision with additional modifications to use an RFP process with
      two separate solicitations. An initial solicitation was held for Penn in May
      2006 with all tranches fully subscribed, which was approved by the PPUC on
      June 2, 2006. On July 18, 2006, the second PLR solicitation was held for
      Penn. The tranches for the Residential Group and Small Commercial Group were
      fully subscribed. However, supply was not acquired for two tranches for the
      Large Commercial Group. On July 20, 2006, the PPUC approved the submissions
      for
      the second bid. A contingency solicitation was held on August 15, 2006 for
      the two remaining Large Commercial Group tranches. The PPUC rejected the bids
      from the contingency solicitation and directed Penn’s independent auction
      manager to offer the two unfilled Large Commercial tranches to the companies
      which had won tranches in the prior solicitations. This resulted in the
      acquisition of a supplier for the two remaining tranches, which were filed
      and
      accepted by the PPUC in a secretarial letter that was entered on
      September 22, 2006. On August 24, 2006, Penn made a compliance filing.
      OCA and OSBA filed exceptions to the compliance filing. Penn filed reply
      exceptions on September 5, 2006. On September 21, 2006, Penn submitted
      a revised compliance filing to the PPUC for the Residential Group and Small
      Commercial Group as a result of an agreement between Penn, OCA and OSBA. The
      PPUC approved proposed rates for the large commercial and industrial customers
      at the PPUC Public meeting on October 19, 2006, and found that the results
      of the competitive solicitation process were consistent with prevailing market
      prices.




On May 25, 2006, Penn filed a Petition for Review of the PPUC’s Orders of
      April 28, 2006 and May 4, 2006, which together decided the issues
      associated with Penn’s proposed Interim PLR Supply Plan. Penn has asked the
      Commonwealth Court to review the PPUC’s decision to deny Penn’s recovery of
      certain PLR costs through a reconciliation mechanism and the PPUC’s decision to
      impose a geographic limitation on the sources of alternative energy credits.
      On
      June 7, 2006, the PaDEP filed a Petition for Review appealing the PPUC’s
      ruling on the method by which alternative energy credits may be acquired and
      traded. Penn is unable to predict the outcome of this appeal.





On
      November 1, 2005,
      FES filed two power sales agreements for approval with the FERC. One power
      sales
      agreement provided for FES to provide the PLR requirements of the Ohio Companies
      at a price equal to the retail generation rates approved by the PUCO for a
      period of three years beginning January 1, 2006. The Ohio Companies will be
      relieved of their obligation to obtain PLR power requirements from FES if the
      Ohio CBP results in a lower price for retail customers. A similar power sales
      agreement between FES and Penn permits Penn to obtain its PLR power requirements
      from FES at a fixed price equal to the retail generation price during 2006.


On
        December 29,
        2005, the FERC issued an order setting the two power sales agreements for
        hearing. The order criticized the Ohio CBP, and required FES to submit
        additional evidence in support of the reasonableness of the prices charged
        in
        the power sales agreements. A pre-hearing conference was held on January
        18,
        2006 to determine the hearing schedule in this case. Under the procedural
        schedule approved in this case, FES expected an initial decision to be issued
        in
        late January 2007. However, on July 14, 2006, the Chief Judge granted the
        joint
        motion of FES and the Trial Staff to appoint a settlement judge in this
        proceeding and the procedural schedule was suspended pending settlement
        discussions among the parties. A settlement conference was held on September
        5,
        2006. FES and the Ohio Companies, Penn, and the PUCO, along
        with other
        parties, reached an agreement to settle the case. The settlement was filed
        with
        the FERC on October 17, 2006, and was unopposed by the remaining parties,
        including the FERC Trial Staff. Initial comments to the settlement are due
        by
        November 6, 2006.
  The
        terms of the
        settlement provide for modification of both the Ohio and Penn power supply
        agreements with FES. Under the Ohio power supply agreement, separate rates
        are
        established for the Ohio Companies’ PLR requirements, special retail contracts
        requirements, wholesale contract requirements, and interruptible buy-through
        retail load requirements. For their PLR and special retail contract
        requirements, the Ohio Companies will pay FES no more than the lower of (i)
        the
        sum of the retail generation charge, the rate stabilization charge, the fuel
        recovery mechanism charge, and FES’ actual incremental fuel costs for such
        sales; or (ii) the wholesale price cap. Different wholesale price caps are
        imposed for PLR sales, special retail contracts, and wholesale contracts.
        The
        wholesale price for interruptible buy-through retail load requirements is
        limited to the actual spot price of power obtained by FES to provide this
        power.
        The Ohio Companies have recognized the estimated additional amount payable
        to
        FES for power supplied during the nine months ended September 30, 2006. The
        wholesale rate charged by FES under the Penn power supply agreement will
        be no
        greater than the generation component of charges for retail PLR load in
        Pennsylvania. The FERC is expected to act on this case by the end of the
        fourth
        quarter of 2006.





91







As
        a result of
        Penn’s PLR competitive solicitation process approved by the PPUC, FES was
        selected as the winning bidder for a number of the tranches for individual
        customer classes. The balance of the tranches will be supplied by unaffiliated
        power suppliers. On October 2, 2006, FES filed an application with FERC under
        Section 205 of the Federal Power Act for authorization to make these affiliate
        sales to Penn. Interventions or protests were due on this filing on October
        23,
        2006. Penn was the only party to file an intervention in this proceeding.
        The
        FERC is expected to act on this filing on or before December 1,
        2006.
  See Note 11 to the consolidated financial statements for further details
        and a complete discussion of regulatory matters in Ohio and Pennsylvania
        and a
        detailed discussion of reliability initiatives, including initiatives by
        the
        PPUC, that impact Penn.


*Environmental
      Matters*




OE accrues environmental liabilities only when it concludes that it is probable
      that it has an obligation for such costs and can reasonably estimate the amount
      of such costs. Unasserted claims are reflected in OE’s determination of
      environmental liabilities and are accrued in the period that they are both
      probable and reasonably estimable.





*W.
      H. Sammis
      Plant-*




In 1999 and 2000, the EPA issued NOV or Compliance Orders to nine utilities
      alleging violations of the Clean Air Act based on operation and maintenance
      of
      44 power plants, including the W. H. Sammis Plant, which was owned at that
      time
      by OE and Penn. In addition, the DOJ filed eight civil complaints against
      various investor-owned utilities, including a complaint against OE and Penn
      in
      the U.S. District Court for the Southern District of Ohio. These cases are
      referred to as New Source Review cases.





On March 18, 2005, OE and Penn announced that they had reached a settlement
      with
      the EPA, the DOJ and three states (Connecticut, New Jersey, and New York) that
      resolved all issues related to the W. H. Sammis Plant New Source Review
      litigation. This settlement agreement was approved by the Court on July 11,
      2005, and requires reductions of NO X and SO 2 emissions at the W.
      H. Sammis Plant and other coal-fired plants through the installation of
      pollution control devices and provides for stipulated penalties for failure
      to
      install and operate such pollution controls in accordance with that agreement.
      Consequently, if FirstEnergy fails to install such pollution control devices,
      for any reason, including, but not limited to, the failure of any third-party
      contractor to timely meet its delivery obligations for such devices, FirstEnergy
      could be exposed to penalties under the settlement agreement. Capital
      expenditures necessary to meet those requirements are currently estimated to
      be
      $1.5 billion ($400 million of which is expected to be spent in 2007 with the
      primary portion of the remaining $1.1 billion expected to be spent in 2008
      and
      2009). On August 26, 2005, FGCO entered into an agreement with Bechtel Power
      Corporation under which Bechtel will engineer, procure, and construct air
      quality control systems for the reduction of SO 2 emissions. FGCO
      also entered into an agreement with B&W on August 25, 2006 to supply flue
      gas desulfurization systems for the reduction of SO 2 emissions.
      Selective Catalytic Reduction (SCR) systems for the reduction of NOx emissions
      also are being installed at the W.H. Sammis Plant under a 1999 agreement with
      B&W. The above requirements will be the responsibility of FGCO.




The settlement agreement also requires OE and Penn to spend up to
      $25 million toward environmentally beneficial projects, which include wind
      energy purchased power agreements over a 20-year term. OE and Penn agreed to
      pay
      a civil penalty of $8.5 million. Results for the first quarter of 2005
      included the penalties paid by OE and Penn of $7.8 million and
      $0.7 million, respectively. OE and Penn also recognized liabilities in the
      first quarter of 2005 of $9.2 million and $0.8 million, respectively,
      for probable future cash contributions toward environmentally beneficial
      projects.





See
      Note 10(B)
      to the consolidated financial statements for further details and a complete
      discussion of environmental matters.





*Other
      Legal
      Proceedings*





There
      are various
      lawsuits, claims (including claims for asbestos exposure) and proceedings
      related to OE’s normal business operations pending against OE and its
      subsidiaries. The other potentially material items not otherwise discussed
      above
      are described below.





92








*Power
      Outages
      and Related Litigation-*




On August 14, 2003, various states and parts of southern Canada experienced
      widespread power outages. The outages affected approximately 1.4 million
      customers in FirstEnergy's service area. The U.S. - Canada Power System Outage
      Task Force’s final report in April 2004 on the outages concluded, among other
      things, that the problems leading to the outages began in FirstEnergy’s Ohio
      service area. Specifically,
      the
      final report concluded, among other things, that the initiation of the
      August 14, 2003 power outages resulted from an alleged failure of both
      FirstEnergy and ECAR to assess and understand perceived inadequacies within
      the
      FirstEnergy system; inadequate situational awareness of the developing
      conditions; and a perceived failure to adequately manage tree growth in certain
      transmission rights of way. The Task Force also concluded that there was a
      failure of the interconnected grid's reliability organizations (MISO and PJM)
      to
      provide effective real-time diagnostic support. The final report is publicly
      available through the Department of Energy’s Web site (www.doe.gov). FirstEnergy
      believes that the final report does not provide a complete and comprehensive
      picture of the conditions that contributed to the August 14, 2003 power
      outages and that it does not adequately address the underlying causes of the
      outages. FirstEnergy remains convinced that the outages cannot be explained
      by
      events on any one utility's system. The final report contained 46
“recommendations to prevent or minimize the scope of future blackouts.”
Forty-five of those recommendations related to broad industry or policy matters
      while one, including subparts, related to activities the Task Force recommended
      be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct
      the
      causes of the August 14, 2003 power outages. FirstEnergy implemented
      several initiatives, both prior to and since the August 14, 2003 power
      outages, which were independently verified by NERC as complete in 2004 and
      were
      consistent with these and other recommendations and collectively enhance the
      reliability of its electric system. FirstEnergy’s implementation of these
      recommendations in 2004 included completion of the Task Force recommendations
      that were directed toward FirstEnergy. FirstEnergy is also proceeding with
      the
      implementation of the recommendations that were to be completed subsequent
      to
      2004 and will continue to periodically assess the FERC-ordered Reliability
      Study
      recommendations for forecasted 2009 system conditions, recognizing revised
      load
      forecasts and other changing system conditions which may impact the
      recommendations. Thus far, implementation of the recommendations has not
      required, nor is expected to require, substantial investment in new or material
      upgrades to existing equipment. The FERC or other applicable government agencies
      and reliability coordinators may, however, take a different view as to
      recommended enhancements or may recommend additional enhancements in the future
      as a result of adoption of mandatory reliability standards pursuant to the
      EPACT
      that could require additional material expenditures.




FirstEnergy companies also are defending six separate complaint cases before
      the
      PUCO relating to the August 14, 2003 power outages. Two cases were
      originally filed in Ohio State courts but were subsequently dismissed for lack
      of subject matter jurisdiction and further appeals were unsuccessful. In these
      cases the individual complainants—three in one case and four in the other—sought
      to represent others as part of a class action. The PUCO dismissed the class
      allegations, stating that its rules of practice do not provide for class action
      complaints. Three other pending PUCO complaint cases were filed by various
      insurance carriers either in their own name as subrogees or in the name of
      their
      insured. In each of these three cases, the carrier seeks reimbursement from
      various FirstEnergy companies (and, in one case, from PJM, MISO and American
      Electric Power Company, Inc., as well) for claims paid to insureds for damages
      allegedly arising as a result of the loss of power on August 14, 2003. The
      listed insureds in these cases, in many instances, are not customers of any
      FirstEnergy company. The sixth case involves the claim of a non-customer seeking
      reimbursement for losses incurred when its store was burglarized on
      August 14, 2003. That case has been dismissed. On
      March 7,
      2006, the PUCO issued a ruling, based on motions filed by the parties,
      applicable to all pending cases. Among its various rulings, the PUCO
      consolidated all of the pending outage cases for hearing; limited the litigation
      to service-related claims by customers of the Ohio operating companies;
      dismissed FirstEnergy as a defendant; ruled that the U.S.-Canada Power System
      Outage Task Force Report was not admissible into evidence; and gave the
      plaintiffs additional time to amend their complaints to otherwise comply with
      the PUCO’s underlying order. Also, most
      complainants, along with the FirstEnergy companies, filed applications for
      rehearing with the PUCO over various rulings contained in the March 7, 2006
      order. On April 26, 2006, the PUCO granted rehearing to allow the insurance
      company claimants, as insurers, to prosecute their claims in their name so
      long
      as they also identify the underlying insured entities and the Ohio utilities
      that provide their service. The PUCO denied all other motions for rehearing.
      The
      plaintiffs in each case have since filed an amended complaint and the named
      FirstEnergy companies have answered and also have filed a motion to dismiss
      each
      action. On September 27, 2006, the PUCO dismissed certain parties and claims
      and
      otherwise ordered the complaints to go forward to hearing. The cases have been
      set for hearing on October 16, 2007.




On October 10, 2006, various insurance carriers refiled a complaint in Cuyahoga
      County Common Pleas Court seeking reimbursement for claims paid to numerous
      insureds who allegedly suffered losses as a result of the August 14, 2003
      outages. All of the insureds appear to be non-customers. The plaintiff insurance
      companies are the same claimants in one of the pending PUCO cases. FirstEnergy,
      the Ohio Companies and Penn were served on October 27, 2006, and expect to
      seek summary dismissal of these cases based on the prior court rulings noted
      above. No estimate of potential liability is available for any of these
      cases.








93







FirstEnergy is vigorously defending these actions, but cannot predict the
      outcome of any of these proceedings or whether any further regulatory
      proceedings or legal actions may be initiated against the Companies. Although
      unable to predict the impact of these proceedings, if FirstEnergy or its
      subsidiaries were ultimately determined to have legal liability in connection
      with these proceedings, it could have a material adverse effect on FirstEnergy's
      or its subsidiaries' financial condition, results of operations and cash
      flows.





*Nuclear
      Plant
      Matters-*




As of December 16, 2005, NGC acquired ownership of the nuclear generation
      assets transferred from OE, Penn, CEI and TE with the exception of leasehold
      interests of OE and TE in certain of the nuclear plants that are subject to
      sale
      and leaseback arrangements with non-affiliates. Excluding OE's retained
      leasehold interests in Beaver Valley Unit 2 (21.66%) and the Perry Nuclear
      Power Plant (12.58%), the transfer included the OE Companies’ prior owned
      interests in Beaver Valley Unit 1 (100%), Beaver Valley Unit 2
      (33.96%) and the Perry Nuclear Power Plant (22.66%).


On August 12, 2004, the NRC notified FENOC that it would increase its
      regulatory oversight of the Perry Nuclear Power Plant as a result of problems
      with safety system equipment over the preceding two years and the licensee's
      failure to take prompt and corrective action. FENOC operates the Perry Nuclear
      Power Plant.




On April 4, 2005, the NRC held a public meeting to discuss FENOC’s
      performance at the Perry Nuclear Power Plant as identified in the NRC's annual
      assessment letter to FENOC. Similar public meetings are held with all nuclear
      power plant licensees following issuance by the NRC of their annual assessments.
      According to the NRC, overall the Perry Nuclear Power Plant operated "in a
      manner that preserved public health and safety" even though it remained under
      heightened NRC oversight. During the public meeting and in the annual
      assessment, the NRC indicated that additional inspections will continue and
      that
      the plant must improve performance to be removed from the Multiple/Repetitive
      Degraded Cornerstone Column of the Action Matrix.




On September 28, 2005, the NRC sent a CAL to FENOC describing commitments
      that FENOC had made to improve the performance at the Perry Nuclear Power Plant
      and stated that the CAL would remain open until substantial improvement was
      demonstrated. The CAL was anticipated as part of the NRC's Reactor Oversight
      Process. In the NRC's 2005 annual assessment letter dated March 2, 2006 and
      associated meetings to discuss the performance of Perry on March 14, 2006,
      the NRC again stated that the Perry Nuclear Power Plant continued to operate
      in
      a manner that "preserved public health and safety." However, the NRC also stated
      that increased levels of regulatory oversight would continue until sustained
      improvement in the performance of the facility was realized. If performance
      does
      not improve, the NRC has a range of options under the Reactor Oversight Process,
      from increased oversight to possible impact to the plant’s operating authority.
      Although FirstEnergy is unable to predict the impact of the ultimate disposition
      of this matter, it could have a material adverse effect on FirstEnergy's or
      its
      subsidiaries' financial condition, results of operations and cash
      flows.





*Other
      Legal
      Matters-*




On October 20, 2004, FirstEnergy was notified by the SEC that the
      previously disclosed informal inquiry initiated by the SEC's Division of
      Enforcement in September 2003 relating to the restatements in August 2003 of
      previously reported results by FirstEnergy and the Ohio Companies, and the
      Davis-Besse extended outage, have become the subject of a formal order of
      investigation. The SEC's formal order of investigation also encompasses issues
      raised during the SEC's examination of FirstEnergy and the Companies under
      the
      now repealed PUHCA. Concurrent with this notification, FirstEnergy received
      a
      subpoena asking for background documents and documents related to the
      restatements and Davis-Besse issues. On December 30, 2004, FirstEnergy
      received a subpoena asking for documents relating to issues raised during the
      SEC's PUHCA examination. On August 24, 2005, additional information was
      requested regarding Davis-Besse related disclosures, which FirstEnergy has
      provided. FirstEnergy has cooperated fully with the informal inquiry and will
      continue to do so with the formal investigation.




On August 22, 2005, a class action complaint was filed against OE in
      Jefferson County, Ohio Common Pleas Court, seeking compensatory and punitive
      damages to be determined at trial based on claims of negligence and eight other
      tort counts alleging damages from W.H. Sammis Plant air emissions. The two
      named
      plaintiffs are also seeking injunctive relief to eliminate harmful emissions
      and
      repair property damage and the institution of a medical monitoring program
      for
      class members. On October 18, 2006, the Ohio Supreme Court transferred this
      case to a Tuscarawas County Common Pleas Court judge due to concerns over
      potential class membership by the Jefferson County Common Pleas
      Court.







94




The City of Huron filed a complaint against OE with the PUCO challenging the
      ability of electric distribution utilities to collect transition charges from
      a
      customer of a newly-formed municipal electric utility. The complaint was filed
      on May 28, 2003, and OE timely filed its response on June 30, 2003. In
      a related filing, the Ohio Companies filed for approval with the PUCO of a
      tariff that would specifically allow the collection of transition charges from
      customers of municipal electric utilities formed after 1998. Both filings were
      consolidated for hearing and decision. An adverse ruling could negatively affect
      full recovery of transition charges by the utility. Hearings on the matter
      were
      held in August 2005. Initial briefs from all parties were filed on
      September 22, 2005 and reply briefs were filed on October 14, 2005. On
      May 10, 2006, the PUCO issued its Opinion and Order dismissing the City’s
      complaint and approving the related tariffs, thus affirming OE’s entitlement to
      recovery of its transition charges. The City of Huron
      filed an application for rehearing of the PUCO’s decision on June 9, 2006
      and OE filed a memorandum in opposition to that application on June 19,
      2006. The PUCO denied the City’s application for rehearing on June 28, 2006. The
      City of Huron has taken no further action and the period for filing an appeal
      has expired.




If it were ultimately determined that FirstEnergy or its subsidiaries have
      legal
      liability or are otherwise made subject to liability based on the above matters,
      it could have a material adverse effect on FirstEnergy’s or its subsidiaries’
financial condition, results of operations and cash flows.





See
      Note 10(C)
      to the consolidated financial statements for further details and a complete
      discussion of these and other legal proceedings.





**NEW
      ACCOUNTING STANDARDS AND INTERPRETATIONS**





*SAB
                108 -
                “Considering the Effects of Prior Year Misstatements when Quantifying
                Misstatements in Current Year Financial
                Statements”*





In September 2006, the SEC issued SAB 108, which provides interpretive guidance
      on how registrants should quantify financial statement misstatements. There
      is
      currently diversity in practice, with the two commonly used methods to quantify
      misstatements being the “rollover” method (which primarily focuses on the income
      statement impact of misstatements) and the “iron curtain” method (which focuses
      on the balance sheet impact). SAB 108 requires registrants to use a dual
      approach whereby both of these methods are considered in evaluating the
      materiality of financial statement errors. Prior materiality assessments will
      need to be reconsidered using both the rollover and iron curtain methods. This
      guidance will be effective for OE in the fourth quarter of 2006. OE does not
      expect this Statement to have a material impact on its financial
      statements.







*SFAS
      157 - “Fair
      Value Measurements”*





In September 2006, the FASB issued SFAS 157 that establishes how companies
      should measure fair value when they are required to use a fair value measure
      for
      recognition or disclosure purposes under GAAP. This Statement addresses the
      need
      for increased consistency and comparability in fair value measurements and
      for
      expanded disclosures about fair value measurements. The key changes to current
      practice are: (1) the definition of fair value which focuses on an exit price
      rather than entry price; (2) the methods used to measure fair value such as
      emphasis that fair value is a market-based measurement, not an entity-specific
      measurement, as well as the inclusion of an adjustment for risk, restrictions
      and credit standing; and (3) the expanded disclosures about fair value
      measurements.





This Statement is effective for financial statements issued for fiscal years
      beginning after November 15, 2007, and interim periods within those years.
      OE is currently evaluating the impact of this Statement on its financial
      statements.





*SFAS
                158 -
                “Employers’ Accounting for Defined Benefit Pension and Other
                Postretirement Plans-an amendment of FASB Statements No. 87, 88,
                106, and
                132(R)”*





In September 2006, the FASB issued SFAS 158, which requires companies to
      recognize a net liability or asset to report the overfunded or underfunded
      status of their defined benefit pension and other postretirement benefit plans
      on their balance sheets and recognize changes in funded status in the year
      in
      which the changes occur through other comprehensive income. The funded status
      to
      be measured is the difference between plan assets at fair value and the benefit
      obligation. This Statement requires that gains and losses and prior service
      costs or credits, net of tax, that arise during the period be recognized as
      a
      component of other comprehensive income and not as components of net periodic
      benefit cost. Additional information should also be disclosed in the notes
      to
      the financial statements about certain effects on net periodic benefit cost
      for
      the next fiscal year that arise from delayed recognition of the gains or losses,
      prior service costs or credits, and transition asset or obligation. Upon the
      initial application of this Statement and subsequently, an employer should
      continue to apply the provisions in Statements 87, 88 and 106 in measuring
      plan
      assets and benefit obligations as of the date of its statement of financial
      position and in determining the amount of net periodic benefit cost. This
      Statement is effective for OE as of December 31, 2006. OE is currently
      evaluating the impact of this Statement on its financial
      statements.





95











*FIN
      48 -
“Accounting for Uncertainty in Income Taxes - an interpretation of FASB
      Statement No. 109.”*





In
      June 2006, the
      FASB issued FIN 48 which clarifies the accounting for uncertainty in income
      taxes recognized in an enterprise’s financial statements in accordance with FASB
      Statement No. 109, “Accounting for Income Taxes.” This interpretation prescribes
      a recognition threshold and measurement attribute for the financial statement
      recognition and measurement of a tax position taken or expected to be taken
      on a
      tax return. This interpretation also provides guidance on derecognition,
      classification, interest, penalties, accounting in interim periods, disclosure
      and transition. The evaluation of a tax position in accordance with this
      interpretation will be a two-step process. The first step will determine if
      it
      is more likely than not that a tax position will be sustained upon examination
      and should therefore be recognized. The second step will measure a tax position
      that meets the more likely than not recognition threshold to determine the
      amount of benefit to recognize in the financial statements. This interpretation
      is effective for fiscal years beginning after December 15, 2006. OE is currently
      evaluating the impact of this Statement.





96




**THE
                  CLEVELAND ELECTRIC ILLUMINATING
                  COMPANY****CONSOLIDATED
                  STATEMENTS OF INCOME AND COMPREHENSIVE
                  INCOME****(Unaudited)****Three
                  Months Ended**
              
              **Nine
                  Months Ended****September
                  30,**
              
              **September
                  30,****2006**
              
              **2005**
              
              **2006**
              
              **2005*****(In
                  thousands)*****STATEMENTS
                  OF INCOME****REVENUES**
              
              $
              515,923
              
              $
              526,421
              
              $
              1,356,104
              
              $
              1,408,341**EXPENSES:**Fuel
              
              
              12,748
              
              
              24,701
              
              
              39,724
              
              
              64,138Purchased
                  power
              
              
              229,779
              
              
              129,640
              
              
              531,490
              
              
              411,366Nuclear
                  operating costs
              
              
              -
              
              
              26,252
              
              
              -
              
              
              121,765Other
                  operating costs
              
              
              81,510
              
              
              89,475
              
              
              222,841
              
              
              227,759Provision
                  for
                  depreciation
              
              
              17,524
              
              
              36,100
              
              
              45,775
              
              
              100,602Amortization
                  of regulatory assets
              
              
              38,826
              
              
              68,455
              
              
              99,832
              
              
              177,497Deferral
                  of
                  new regulatory assets
              
              
              (39,060
              )
              
              (60,519
              )
              
              (101,283
              )
              
              (126,508
              )General
                  taxes
              
              
              34,228
              
              
              40,054
              
              
              100,808
              
              
              115,546Total
                  expenses
              
              
              375,555
              
              
              354,158
              
              
              939,187
              
              
              1,092,165**OPERATING
                  INCOME**
              
              
              140,368
              
              
              172,263
              
              
              416,917
              
              
              316,176**OTHER
                  INCOME (EXPENSE):**Investment
                  income
              
              
              24,715
              
              
              36,629
              
              
              76,325
              
              
              65,826Miscellaneous
                  income (expense)
              
              
              813
              
              
              411
              
              
              6,209
              
              
              (8,353
              )Interest
                  expense
              
              
              (34,774
              )
              
              (31,786
              )
              
              (104,140
              )
              
              (96,404
              )Capitalized
                  interest
              
              
              836
              
              
              1,129
              
              
              2,346
              
              
              2,012Total
                  other
                  income (expense)
              
              
              (8,410
              )
              
              6,383
              
              
              (19,260
              )
              
              (36,919
              )**INCOME
                  BEFORE INCOME TAXES**
              
              
              131,958
              
              
              178,646
              
              
              397,657
              
              
              279,257**INCOME
                  TAXES**
              
              
              48,496
              
              
              68,209
              
              
              150,730
              
              
              114,679**NET
                  INCOME**
              
              
              83,462
              
              
              110,437
              
              
              246,927
              
              
              164,578**PREFERRED
                  STOCK DIVIDEND REQUIREMENTS**
              
              
              -
              
              
              -
              
              
              -
              
              
              2,918**EARNINGS
                  ON COMMON STOCK**
              
              $
              83,462
              
              $
              110,437
              
              $
              246,927
              
              $
              161,660**STATEMENTS
                  OF COMPREHENSIVE INCOME****NET
                  INCOME**
              
              $
              83,462
              
              $
              110,437
              
              $
              246,927
              
              $
              164,578**OTHER
                  COMPREHENSIVE INCOME (LOSS):**Unrealized
                  loss on available for sale securities
              
              
              -
              
              
              (6,574
              )
              
              -
              
              
              (9,144
              )Income
                  tax
                  benefit related to other comprehensive loss
              
              
              -
              
              
              2,510
              
              
              -
              
              
              3,433Other
                  comprehensive loss, net of tax
              
              
              -
              
              
              (4,064
              )
              
              -
              
              
              (5,711
              )**TOTAL
                  COMPREHENSIVE INCOME**
              
              $
              83,462
              
              $
              106,373
              
              $
              246,927
              
              $
              158,867The
                  preceding
                  Notes to Consolidated Financial Statements as they relate to The
                  Cleveland
                  Electric Illuminating Company are anintegral
                  part
                  of these statements.
   97
  **THE
                    CLEVELAND ELECTRIC ILLUMINATING
                    COMPANY****CONSOLIDATED
                    BALANCE SHEETS****(Unaudited)****September
                    30,**
                
                **December
                    31,****2006**
                
                **2005*****(In
                    thousands)*****ASSETS****CURRENT
                    ASSETS:**Cash
                    and cash
                    equivalents
                
                $
                223
                
                $
                207Receivables-Customers
                    (less accumulated provisions of $6,819,000 and$5,180,000,
                    respectively, for uncollectible accounts)
                
                
                283,267
                
                
                268,427Associated
                    companies
                
                
                63,926
                
                
                86,564Other
                
                
                24,075
                
                
                16,466Notes
                    receivable from associated companies
                
                
                29,184
                
                
                19,378Prepayments
                    and other
                
                
                2,290
                
                
                1,903402,965
                
                
                392,945**UTILITY
                    PLANT:**In
                    service
                
                
                2,082,224
                
                
                2,030,935Less
                    -
                    Accumulated provision for depreciation
                
                
                808,728
                
                
                788,9671,273,496
                
                
                1,241,968Construction
                    work in progress
                
                
                75,127
                
                
                51,1291,348,623
                
                
                1,293,097**OTHER
                    PROPERTY AND INVESTMENTS:**Long-term
                    notes receivable from associated companies
                
                
                940,786
                
                
                1,057,337Investment
                    in
                    lessor notes
                
                
                519,613
                
                
                564,166Other
                
                
                13,631
                
                
                12,8401,474,030
                
                
                1,634,343**DEFERRED
                    CHARGES AND OTHER ASSETS:**Goodwill
                
                
                1,688,521
                
                
                1,688,966Regulatory
                    assets
                
                
                854,525
                
                
                862,193Prepaid
                    pension costs
                
                
                136,116
                
                
                139,012Property
                    taxes
                
                
                63,500
                
                
                63,500Other
                
                
                26,261
                
                
                27,6142,768,923
                
                
                2,781,285$
                5,994,541
                
                $
                6,101,670**LIABILITIES
                    AND CAPITALIZATION****CURRENT
                    LIABILITIES:**Currently
                    payable long-term debt
                
                $
                120,556
                
                $
                75,718Short-term
                    borrowings-Associated
                    companies
                
                
                302,588
                
                
                212,256Other
                
                
                -
                
                
                140,000Accounts
                    payable-Associated
                    companies
                
                
                103,449
                
                
                74,993Other
                
                
                5,889
                
                
                4,664Accrued
                    taxes
                
                
                106,899
                
                
                121,487Accrued
                    interest
                
                
                31,313
                
                
                18,886Lease
                    market
                    valuation liability
                
                
                60,200
                
                
                60,200Other
                
                
                48,661
                
                
                61,308779,555
                
                
                769,512**CAPITALIZATION:**Common
                    stockholder's equity-Common
                    stock,
                    without par value, authorized 105,000,000 shares -79,590,689
                    shares outstanding
                
                
                1,355,957
                
                
                1,354,924Retained
                    earnings
                
                
                716,077
                
                
                587,150Total
                    common
                    stockholder's equity
                
                
                2,072,034
                
                
                1,942,074Long-term
                    debt
                    and other long-term obligations
                
                
                1,766,195
                
                
                1,939,3003,838,229
                
                
                3,881,374**NONCURRENT
                    LIABILITIES:**Accumulated
                    deferred income taxes
                
                
                547,307
                
                
                554,828Accumulated
                    deferred investment tax credits
                
                
                21,185
                
                
                23,908Lease
                    market
                    valuation liability
                
                
                562,900
                
                
                608,000Retirement
                    benefits
                
                
                83,615
                
                
                83,414Deferred
                    revenues - electric service programs
                
                
                57,638
                
                
                71,261Other
                
                
                104,112
                
                
                109,3731,376,757
                
                
                1,450,784**COMMITMENTS
                    AND CONTINGENCIES (Note 10)**$
                5,994,541
                
                $
                6,101,670The
                    preceding
                    Notes to Consolidated Financial Statements as they relate to
                    The Cleveland
                    Electric Illuminating Companyare
                    an
                    integral part of these balance sheets.
   98
  **THE
                      CLEVELAND ELECTRIC ILLUMINATING
                      COMPANY****CONSOLIDATED
                      STATEMENTS OF CASH FLOWS****(Unaudited)****Nine
                      Months Ended****September
                      30,****2006**
                  
                  **2005*****(In
                      thousands)*****CASH
                      FLOWS FROM OPERATING ACTIVITIES:**Net
                      income
                  
                  $
                  246,927
                  
                  $
                  164,578Adjustments
                      to
                      reconcile net income to net cash from operating activities
                      -Provision
                      for
                      depreciation
                  
                  
                  45,775
                  
                  
                  100,602Amortization
                      of regulatory assets
                  
                  
                  99,832
                  
                  
                  177,497Deferral
                      of
                      new regulatory assets
                  
                  
                  (101,283
                  )
                  
                  (126,508
                  )Nuclear
                      fuel
                      and capital lease amortization
                  
                  
                  179
                  
                  
                  19,017Deferred
                      rents
                      and lease market valuation liability
                  
                  
                  (55,166
                  )
                  
                  (67,130
                  )Deferred
                      income taxes and investment tax credits, net
                  
                  
                  (9,513
                  )
                  
                  14,934Accrued
                      compensation and retirement benefits
                  
                  
                  2,681
                  
                  
                  2,997Decrease
                      (increase) in operating assets-Receivables
                  
                  
                  189
                  
                  
                  (87,567
                  )Materials
                      and
                      supplies
                  
                  
                  -
                  
                  
                  (13,584
                  )Prepayments
                      and other current assets
                  
                  
                  (387
                  )
                  
                  (633
                  )Increase
                      (decrease) in operating liabilities-Accounts
                      payable
                  
                  
                  29,681
                  
                  
                  (118,908
                  )Accrued
                      taxes
                  
                  
                  (14,588
                  )
                  
                  27,176Accrued
                      interest
                  
                  
                  12,427
                  
                  
                  5,140Electric
                      service prepayment programs
                  
                  
                  (13,623
                  )
                  
                  55,311Other
                  
                  
                  (5,449
                  )
                  
                  (26,328
                  )Net
                      cash
                      provided from operating activities
                  
                  
                  237,682
                  
                  
                  126,594**CASH
                      FLOWS FROM FINANCING ACTIVITIES:**New
                      Financing-Long-term
                      debt
                  
                  
                  -
                  
                  
                  141,056Short-term
                      borrowings, net
                  
                  
                  -
                  
                  
                  53,369Equity
                      contributions from parent
                  
                  
                  -
                  
                  
                  75,000Redemptions
                      and Repayments-Preferred
                      stock
                  
                  
                  -
                  
                  
                  (101,900
                  )Long-term
                      debt
                  
                  
                  (118,295
                  )
                  
                  (147,789
                  )Short-term
                      borrowings, net
                  
                  
                  (58,819
                  )
                  
                  -Dividend
                      Payments-Common
                      stock
                  
                  
                  (118,000
                  )
                  
                  (141,000
                  )Preferred
                      stock
                  
                  
                  -
                  
                  
                  (2,260
                  )Net
                      cash used
                      for financing activities
                  
                  
                  (295,114
                  )
                  
                  (123,524
                  )**CASH
                      FLOWS FROM INVESTING ACTIVITIES:**Property
                      additions
                  
                  
                  (89,771
                  )
                  
                  (98,053
                  )Loan
                      repayments from associated companies, net
                  
                  
                  108,034
                  
                  
                  89,236Investments
                      in
                      lessor notes
                  
                  
                  44,553
                  
                  
                  32,476Proceeds
                      from
                      nuclear decommissioning trust fund sales
                  
                  
                  -
                  
                  
                  376,309Investments
                      in
                      nuclear decommissioning trust funds
                  
                  
                  -
                  
                  
                  (398,077
                  )Other
                  
                  
                  (5,368
                  )
                  
                  (4,951
                  )Net
                      cash
                      provided from (used for) investing activities
                  
                  
                  57,448
                  
                  
                  (3,060
                  )Net
                      increase
                      in cash and cash equivalents
                  
                  
                  16
                  
                  
                  10Cash
                      and cash
                      equivalents at beginning of period
                  
                  
                  207
                  
                  
                  197Cash
                      and cash
                      equivalents at end of period
                  
                  $
                  223
                  
                  $
                  207The
                      preceding
                      Notes to Consolidated Financial Statements as they relate to
                      The Cleveland
                      Electric Illuminating Companyare
                      an
                      integral part of these statements.
   99








***Report
      of Independent Registered Public Accounting Firm***





























To
      the Stockholder
      and Board of


Directors
      of The
      Cleveland Electric Illuminating Company:





We
      have reviewed the
      accompanying consolidated balance sheet of The Cleveland Electric Illuminating
      Company and its subsidiaries as of September 30, 2006, and the related
      consolidated statements of income and comprehensive income for each of the
      three-month and nine-month periods ended September 30, 2006 and 2005 and the
      consolidated statements of cash flows for the nine-month periods ended September
      30, 2006 and 2005. These interim financial statements are the responsibility
      of
      the Company’s management.





We
      conducted our
      review in accordance with the standards of the Public Company Accounting
      Oversight Board (United States). A review of interim financial information
      consists principally of applying analytical procedures and making inquiries
      of
      persons responsible for financial and accounting matters. It is substantially
      less in scope than an audit conducted in accordance with the standards of the
      Public Company Accounting Oversight Board, the objective of which is the
      expression of an opinion regarding the financial statements taken as a whole.
      Accordingly, we do not express such an opinion.





Based
      on our review,
      we are not aware of any material modifications that should be made to the
      accompanying consolidated interim financial statements for them to be in
      conformity with accounting principles generally accepted in the United States
      of
      America.





We
      have previously
      audited, in accordance with the standards of the Public Company Accounting
      Oversight Board (United States), the consolidated balance sheet as of December
      31, 2005, and the related consolidated statements of income, capitalization,
      common stockholder’s equity, preferred stock, cash flows and taxes for the year
      then ended (not presented herein), and in our report [which contained references
      to the Company’s change in its method of accounting for asset retirement
      obligations as of January 1, 2003 and conditional asset retirement obligations
      as of December 31, 2005 as discussed in Note 2(G) and Note 11 to those
      consolidated financial statements and the Company’s change in its method of
      accounting for the consolidation of variable interest entities as of December
      31, 2003 as discussed in Note 6 to those consolidated financial statements]
      dated February 27, 2006, we expressed an unqualified opinion on those
      consolidated financial statements. In our opinion, the information set forth
      in
      the accompanying consolidated balance sheet as of December 31, 2005, is fairly
      stated in all material respects in relation to the consolidated balance sheet
      from which it has been derived.





PricewaterhouseCoopers
                LLP
              Cleveland,
                Ohio
              October
                31,
                2006











100





**THE
      CLEVELAND ELECTRIC ILLUMINATING COMPANY**





**MANAGEMENT’S
      DISCUSSION AND ANALYSIS OF**


**RESULTS
      OF
      OPERATIONS AND FINANCIAL CONDITION**








CEI
      is a wholly
      owned, electric utility subsidiary of FirstEnergy. CEI conducts business in
      portions of Ohio, providing regulated electric distribution services. CEI also
      provides generation services to those customers electing to retain CEI as their
      power supplier. CEI’s power supply requirements are primarily provided by FES - an affiliated
      company.





**FirstEnergy
      Intra-System Generation Asset Transfers**




In 2005, the Ohio Companies and Penn entered into certain agreements
      implementing a series of intra-system generation asset transfers that were
      completed in the fourth quarter of 2005. The asset transfers resulted in the
      respective undivided ownership interests of the Ohio Companies and Penn in
      FirstEnergy’s nuclear and non-nuclear generation assets being owned by NGC and
      FGCO, respectively. The generating plant interests transferred did not include
      CEI’s leasehold interests in certain of the plants that are currently subject to
      sale and leaseback arrangements with non-affiliates.




On October 24, 2005, CEI completed the intra-system transfer of non-nuclear
      generation assets to FGCO. Prior to the transfer, FGCO, as lessee under a Master
      Facility Lease with the Ohio Companies and Penn, leased, operated and maintained
      the non-nuclear generation assets that it now owns. The asset transfers were
      consummated pursuant to FGCO's purchase option under the Master Facility
      Lease.




On December 16, 2005, CEI completed the intra-system transfer of its
      ownership interests in the nuclear generation assets to NGC through a sale
      at
      net book value. FENOC continues to operate and maintain the nuclear generation
      assets.




These transactions were undertaken pursuant to the Ohio Companies’ and Penn’s
      restructuring plans that were approved by the PUCO and the PPUC, respectively,
      under applicable Ohio and Pennsylvania electric utility restructuring
      legislation. Consistent with the restructuring plans, generation assets that
      had
      been owned by the Ohio Companies and Penn were required to be separated from
      the
      regulated delivery business of those companies through transfer to a separate
      corporate entity. The transactions essentially completed the divestitures
      contemplated by the restructuring plans by transferring the ownership interests
      to NGC and FGCO without impacting the operation of the plants.




The transfers will affect CEI’s comparative earnings results with reductions in
      both revenues and expenses. Revenues are reduced due to the termination of
      certain arrangements with FES, under which CEI previously sold its
      nuclear-generated KWH to FES and leased its non-nuclear generation assets to
      FGCO, a subsidiary of FES. CEI’s expenses are lower due to the nuclear fuel and
      operating costs assumed by NGC as well as depreciation and property tax expenses
      assumed by FGCO and NGC related to the transferred generating assets. With
      respect to CEI's retained leasehold interests in the Bruce Mansfield Plant,
      CEI
      has continued the fossil generation KWH sales arrangement with FES and continues
      to be obligated on the applicable portion of expenses related to those
      interests. In addition, CEI receives interest income on associated company
      notes
      receivable from the transfer of its generation net assets. FES continues to
      provide CEI’s PLR requirements under revised purchased power arrangements
      covering the three-year period beginning January 1, 2006 (see Regulatory
      Matters).








101




The effects on CEI’s results of operations in the third quarter and nine months
      ended September 30, 2006 compared to the same periods of 2005 from the
      generation asset transfers (also reflecting CEI's retained leasehold interests
      discussed above) are summarized in the following table:





**Intra-System
                Generation Asset Transfers****Income
                Statement Effects**
            
            **Three
                Months**
            
            
            **Nine
                Months****Increase
                (Decrease)**
            
            ***(In
                millions)***Revenues:Non-nuclear
                generating units rent
            (a)
            $
            (15)
            
            
            $
            (44)Nuclear-generated
                KWH sales
            (b)
            
            (80)
            
            
            
            (190)Total
                -
                Revenues Effect
            
            
            (95)
            
            
            
            (234)Expenses:Fuel
                costs -
                nuclear
            (c)
            
            (10)
            
            
            
            (24)Nuclear
                operating costs
            (c)
            
            (27)
            
            
            
            (122)Provision
                for
                depreciation
            (d)
            
            (16)
            
            
            
            (48)General
                taxes
            (e)
            
            (3)
            
            
            
            (11)Total
                -
                Expenses Effect
            
            
            (56)
            
            
            
            (205)Operating
                Income Effect
            
            
            (39)
            
            
            
            (29)Other
                Income:Interest
                income from notes receivable
            (f)
            
            14
            
            
            
            44Nuclear
                decommissioning trust earnings
            (g)
            
            (23)
            
            
            
            (27)Capitalized
                interest
            (h)
            
            (1)
            
            
            
            (1)Total
                - Other
                Income Effect
            
            
            (10)
            
            
            
            16Income
                taxes
            (i)
            
            (20)
            
            
            
            (5)Net
                Income
                Effect
            
            $
            (29)
            
            
            $
            (8)(a)
                Elimination of non-nuclear generation assets lease to
                FGCO.(b)
                Reduction
                of nuclear-generated wholesale KWH sales to FES.(c)
                Reduction
                of nuclear fuel and operating costs.(d)
                Reduction
                of depreciation expense and asset retirement obligation accretion
                related
                to generation assets.(e)
                Reduction
                of property tax expense on generation assets.(f)
                Interest
                income on associated company notes receivable from the transfer of
                generation net assets.(g)
                Reduction
                of earnings on nuclear decommissioning trusts.(h)
                Reduction
                of allowance for borrowed funds used during construction on nuclear
                capital expenditures.(i)
                Income tax
                effect of the above adjustments.





**Results
      of Operations**


Earnings
          on common
          stock in the third quarter of 2006 decreased to $83 million from $110
          million in the third quarter of 2005. In the first nine months of 2006,
          earnings
          on common stock increased to $247 million from $162 million in the same
          period of 2005. The change in earnings in both periods reflected the effects
          of
          the generation asset transfer shown in the table above. Expenses during
          the
          third quarter of 2006 included $19 million of costs associated with the
          proposed FERC settlement (see Note 11) applicable to the first half of
          2006. The
          increase in the nine month period also reflected the absence of the
          $2 million Davis-Besse fine in the first quarter of 2005 and the
          $8 million impact of the Ohio tax change implementation in the second
          quarter of 2005.
  *Revenues*





Revenues
      decreased
      by $10 million or 2.0% in the third quarter of 2006 from the same period in
      2005. Excluding
      the
      effects of the generation asset transfers displayed above, revenues increased
      $85 million due to a $137 million increase in retail generation sales
      revenues and a $41 million reduction in customer shopping incentives, partially
      offset by a $76 million decrease in distribution revenues and a $17 million
      decrease in non-affiliated wholesale sales. In the first nine months of 2006
      compared to the same period in 2005, revenues decreased by $52 million or 3.7%.
      Excluding the effects of the generation asset transfers discussed above,
      revenues increased $182 million due to a $331 million increase in retail
      generation sales revenues and an $88 million reduction in customer shopping
      incentives, partially offset by a $182 million decrease in distribution
      revenues and a $55 million decrease in non-affiliated wholesale
      sales.





102








The
      non-affiliated
      wholesale sales revenues decreases for the third quarter and the first nine
      months of 2006 compared with the same periods in 2005 resulted from the December
      2005 cessation of the MSG sales arrangements under CEI’s transition plan. CEI
      had been required to provide the MSG to non-affiliated alternative
      suppliers.





Changes
      in electric
      generation KWH sales and revenues
      in the
      third quarter and first nine months of 2006 from the corresponding periods
      of
      2005 are summarized in the following tables.





**Changes
                in Generation KWH Sales**
            
            **Three
                Months**
            
            **Nine
                Months****Increase
                (Decrease)**Electric
                Generation:Retail
            
            
            61.6
            %
            
            52.9
            %Wholesale
            
            
            (81.6)
            %
            
            (75.5)
            %**Net
                Decrease in Generation Sales**
            
            
            **(26.8)**
            **%**
            
            **(21.1)**
            **%**





**Changes
                in Generation Revenues**
            
            
            **Three
                Months**
            
            
            **Nine
                Months****Increase
                (Decrease)**
            
            
            ***(In
                millions)***Retail
                Generation:Residential
            
            $
            55
            
            $
            132Commercial
            
            
            48
            
            
            118Industrial
            
            
            34
            
            
            81Total
                Retail
                Generation
            
            
            137
            
            
            331Wholesale*
            
            
            (17
            )
            
            (55
            )**Net
                Increase in Generation Revenues**
            
            **$**
            **120**
            
            **$**
            **276**





*Excludes
      impact of
      generation asset transfers related to nuclear generated KWH sales.





Increased
      retail
      generation revenues for the third quarter of 2006 compared with the same period
      of 2005 (as shown in the table above) were due to higher unit prices and
      increased KWH sales. The higher unit prices for generation reflected the rate
      stabilization charge that became effective in the first quarter of 2006 under
      provisions of the RSP and RCP. The increase in generation KWH sales resulted
      from decreased customer shopping. Generation services provided by alternative
      suppliers as a percent of total sales delivered in CEI's service area decreased
      by: residential - 62.4 percentage points, commercial - 46.1 percentage points
      and industrial - 9.8 percentage points. The decreased shopping resulted from
      certain alternative energy suppliers terminating their supply arrangements
      with
      CEI's shopping customers in the fourth quarter of 2005.





Increased
      retail
      generation revenues in the first nine months of 2006 compared with the same
      period in 2005 were due to the reasons discussed above. The increase in
      generation KWH sales reflected a similar decrease in customer shopping also
      as
      discussed above. This resulted in similar percentage decreases in the first
      nine
      months of 2006 in generation services provided by alternative suppliers as
      a
      percentage of total sales deliveries in CEI's service area (residential - 60.9
      percentage points, commercial - 42.9 percentage points and industrial - 8.3
      percentage points).





Changes
      in
      distribution KWH deliveries and revenues
      in the
      third quarter and first nine months of 2006 from the corresponding periods
      of
      2005 are summarized in the following tables.





**Changes
                in Distribution KWH Sales**
            
            **Three
                Months**
            
            **Nine
                Months****Increase
                (Decrease)**Distribution
                Deliveries:Residential
            
            (6.3)
            %
            (4.7)
            %Commercial
            
            (3.5)
            %
            (4.0)
            %Industrial
            
            1.2
            %
            (1.3)
            %**Net
                Decrease in Distribution Deliveries**
            
            **(2.3)**
            %
            **(3.0)**
            %





**Changes
                in Distribution Revenues**
            
            **Three
                Months**
            
            **Nine
                Months****Increase
                (Decrease)**
            
            ***(In
                millions)***Residential
            
            $
            (25)
            
            $
            (46)Commercial
            
            
            (29)
            
            
            (74)Industrial
            
            
            (22)
            
            
            (62)**Net
                Decrease in Distribution Revenues**
            
            **$**
            **(76)**
            
            **$**
            **(182)**








103








Lower
      distribution
      revenues shown in the table above for the third quarter and first nine months
      of
      2006 primarily
      reflected
      lower unit prices and decreased KWH deliveries. The lower unit prices reflected
      the completion of the generation-related transition cost recovery under CEI’s
      transition plan in 2005, partially offset by increased transmission rates to
      recover MISO costs beginning in 2006 (see Outlook -- Regulatory Matters). The lower
      KWH distribution deliveries to residential and commercial customers were
      primarily due to milder weather conditions in the third quarter and first nine
      months of 2006, compared to the same periods of 2005.





Under
      the Ohio
      transition plan, CEI provided incentives to customers to encourage switching
      to
      alternative energy providers, reducing CEI's revenues. These revenue reductions,
      which were deferred for future recovery and did not affect earnings, ceased
      in
      2006, resulting in a $41 million revenue increase for the third quarter of
      2006
      and an $88 million increase for the first nine months of 2006 compared to the
      same periods of 2005, as discussed above.





*Expenses*


Total
          expenses
          increased by $22 million in the third quarter of 2006 and decreased by
          $159 million in the first nine months of 2006 from the same periods of
          2005. The change in both periods was impacted by the effects of the
          generation asset transfers shown in the table above. Excluding the asset
          transfer effects, the following table presents changes from the prior year
          by
          expense category:


**Expenses
                - Changes**
            
            **Three
                Months**
            
            **Nine
                Months****Increase
                (Decrease)**
            
            ***(In
                millions)***Fuel
                costs
            
            $
            (1
            )
            $
            -Purchased
                power costs
            
            
            100
            
            
            120Other
                operating costs
            
            
            (8
            )
            
            (5
            )Provision
                for
                depreciation
            
            
            (3
            )
            
            (7
            )Amortization
                of regulatory assets
            
            
            (30
            )
            
            (78
            )Deferral
                of
                new regulatory assets
            
            
            21
            
            
            25General
                taxes
            
            
            (2
            )
            
            (3
            )**Net
                increase in expenses**
            
            $
            77
            
            $
            52




Higher
        purchased
        power costs in the third quarter and the first nine months of 2006 as compared
        to the same periods of 2005 resulted from increased KWH purchases and higher
        unit prices. Greater KWH purchases primarily reflected higher retail generation
        sales requirements and the higher unit prices are primarily due to the current
        power supply agreement with FES. Lower other operating costs in both periods
        of
        2006 compared with the same periods in 2005 reflected the absence in 2006
        of
        transmission expenses related to the 2005 competitive retail energy supplier
        reimbursements which were discontinued at the end of 2005. In addition,
        decreased employee and contractor costs resulted from lower storm-related
        expenses and decreased contractor costs for vegetation management. Partially
        offsetting the lower other operating costs were greater transmission expenses
        in
        both periods that primarily relate to MISO Day 2 operations that began on
        April 1, 2005.
  Excluding the effects of the generation asset transfers, the
        depreciation
        decrease in the first nine months of 2006 compared to 2005 was primarily
        attributable to a second quarter 2006 pretax credit adjustment of $6.5 million
        ($4 million net of tax) applicable to prior periods. Lower
        amortization
        of regulatory assets in both periods of 2006 reflected the completion of
        generation-related transition cost amortization under CEI’s transition plan,
        partially offset by the amortization of deferred MISO costs that are being
        recovered in 2006. The
        decreased
        deferral of new regulatory assets in the third quarter and first nine months
        of
        2006 compared with the same periods in 2005 was primarily due to the termination
        of the shopping incentive deferrals ($41 million and $87 million, respectively)
        and lower MISO cost deferrals ($12 million and $16 million, respectively),
        partially offset by the deferrals of distribution costs ($16 million and
        $44 million, respectively) and fuel costs ($16 million and $34 million,
        respectively) under the RCP. The deferral of interest on the unamortized
        shopping incentive balances continues under the RCP.





104





*Other
      Income*





The
      change in other
      income for both periods reflected the generation asset transfers discussed
      above. Excluding the effects of the asset transfer, other income decreased
      by $6
      million in the third quarter of 2006 as a result of greater interest expense
      due
      to the absence of refinancing cost reductions recognized in 2005. Excluding
      the
      effects of the asset transfer, other income increased by $2 million in the
      first
      nine months of 2006 and was primarily due to a $6 million benefit recognized
      in
      the second quarter of 2006 related to the sale of the Ashtabula C Plant,
      partially offset by increased interest expense in 2006.





*Income
      Taxes*


Income
        taxes
        decreased by $20 million in the third quarter of 2006 and increased by $36 million
        in
        the first nine months of 2006 compared to the same periods of 2005. Excluding
        the effects of the generation asset transfer, income taxes were unchanged
        in the
        third quarter of 2006 and increased by $41 million in first nine months of
        2006. The increase in the first nine months of 2006 was primarily due to
        an
        increase in taxable income, partially offset by the absence in 2006 of $8
        million of additional income tax expenses from the implementation of Ohio
        tax
        legislation changes in the second quarter of 2005.


*Preferred
      Stock
      Dividend Requirements*





Preferred
      stock
      dividend requirements decreased by $3 million in the first nine months of 2006,
      compared to the same period last year, as a result of the optional redemption
      of
      CEI's remaining outstanding preferred stock in 2005.





**Capital
      Resources and Liquidity**




During the remainder of 2006, CEI expects to meet its contractual obligations
      with cash from operations, short-term credit arrangements and funds from capital
      markets. Thereafter, CEI expects to use a combination of cash from operations
      and funds from the capital markets.





*Changes
      in Cash
      Position*




As of September 30, 2006, CEI had $223,000 of cash and cash equivalents,
      compared with $207,000 as of December 31, 2005. The major sources of changes
      in
      these balances are summarized below.





*Cash
      Flows from
      Operating Activities*





Cash
      provided from
      operating activities during the first nine months of 2006, compared with the
      same period last year, were as follows:





**Nine
                Months Ended**
              **September
                30,****Operating
                Cash Flows**
            
            **2006**
            
            **2005*****(In
                millions)***Cash
                earnings*
            
            $
            216
            
            $
            274Working
                capital and other
            
            
            22
            
            
            (147
            )Net
                cash
                provided from operating activities
            
            $
            238
            
            $
            127





*
      Cash earnings are a non-GAAP measure (see reconciliation below).





Cash
      earnings (in
      the table above) are not a measure of performance calculated in accordance
      with
      GAAP. CEI believes that cash earnings is a useful financial measure because
      it
      provides investors and management with an additional means of evaluating its
      cash-based operating performance. Generally, a non-GAAP financial measure is
      a
      numerical measure of a company’s historical or future financial performance,
      financial position, or cash flows that either excludes or includes amounts,
      or
      is subject to adjustment that has the effect of excluding or including amounts,
      that are not normally excluded or included in the most directly comparable
      measure calculated and presented in accordance with GAAP. In addition, cash
      earnings (non-GAAP) are not defined under GAAP. Management believes presenting
      this non-GAAP measure provides useful information to investors in assessing
      CEI’s operating performance from a cash perspective without the effects of
      material unusual economic events. CEI’s management frequently references these
      non-GAAP financial measures in its decision-making, using them to facilitate
      historical and ongoing performance comparisons as well as comparisons to the
      performance of peer companies. These non-GAAP measures should be considered
      in
      addition to, and not as a substitute for, their most directly comparable
      financial measures prepared in accordance with GAAP.





105








**Nine
                Months Ended****September
                30,****Reconciliation
                of Cash Earnings**
            
            **2006**
            
            **2005*****(In
                millions)***Net
                Income
                (GAAP)
            
            $
            247
            
            $
            165Non-cash
                charges (credits):Provision
                for
                depreciation
            
            
            46
            
            
            101Amortization
                of regulatory assets
            
            
            100
            
            
            177Deferral
                of
                new regulatory assets
            
            
            (101)
            
            
            (127)Nuclear
                fuel
                and capital lease amortization
            
            
            -
            
            
            19Amortization
                of electric service obligation
            
            
            (14)
            
            
            (12)Deferred
                rents
                and lease market valuation liability
            
            
            (
                55)
            
            
            (67)Deferred
                income taxes and investment tax credits, net
            
            
            (10)
            
            
            15Accrued
                compensation and retirement benefits
            
            
            3
            
            
            3Cash
                earnings
                (Non-GAAP)
            
            $
            216
            
            $
            274




Net
        cash provided
        from operating activities increased by $111 million in the first nine months
        of
        2006 from the same period last year as a result of a $169 million increase
        in working capital and other cash flows, partially offset by a $58 million
        decrease in cash earnings described above under "Results of Operations."
        The
        largest factors contributing to the changes in working capital and other
        operating cash flows for the first nine months of 2006 are changes in accounts
        receivable related to the 2005 conversion of the CFC receivables financing
        ($155
        million) to on-balance sheet transactions and changes in accounts payable,
        offset in part by the absence of funds received in 2005 for prepaid electric
        service under the Energy for Education Program.
  *Cash
        Flows from
        Financing Activities*





Net
      cash used for
      financing activities increased by $172 million in the first nine months of
      2006
      from the same period last year. The increase in funds used for financing
      activities primarily resulted from a $122 million increase in net preferred
      stock and debt redemptions and the absence of a $75 million equity contribution
      from FirstEnergy in 2005, partially offset by a $23 million decrease in common
      stock dividend payments to FirstEnergy.





CEI
      had $29 million
      of cash and temporary investments (which included short-term notes receivable
      from associated companies) and approximately $303 million of short-term
      indebtedness as of September 30, 2006. CEI has obtained authorization from
      the
      PUCO to incur short-term debt of up to $600 million (including the bank
      facility and utility money pool described below).





As
      of September 30,
      2006, CEI had the capability to issue $259 million of additional FMB on the
      basis of property additions and retired bonds under the terms of its mortgage
      indenture. The issuance of FMB by CEI is subject to a provision of its senior
      note indenture generally limiting the incurrence of additional secured debt,
      subject to certain exceptions that would permit, among other things, the
      issuance of secured debt (including FMB) (i) supporting pollution control notes
      or similar obligations, or (ii) as an extension, renewal or replacement of
      previously outstanding secured debt. In addition, CEI is permitted under the
      indenture to incur additional secured debt not otherwise permitted by a
      specified exception of up to $579 million as of September 30, 2006. CEI has
      no restrictions on the issuance of preferred stock.





CFC
      is a wholly
      owned subsidiary of CEI whose borrowings are secured by customer accounts
      receivable purchased from CEI and TE. CFC can borrow up to $200 million under
      a
      receivables financing arrangement. As a separate legal entity with separate
      creditors, CFC would have to satisfy its obligations to creditors before any
      of
      its remaining assets could be made available to CEI. As of September 30, 2006,
      the facility was not drawn.





CEI
      has the ability
      to borrow from its regulated affiliates and FirstEnergy to meet its short-term
      working capital requirements. FESC administers this money pool and tracks
      surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving
      a loan under the money pool agreements must repay the principal amount, together
      with accrued interest, within 364 days of borrowing the funds. The rate of
      interest is the same for each company receiving a loan from the pool and is
      based on the average cost of funds available through the pool. The average
      interest rate for borrowings in the first nine months of 2006 was
      5.09%.





106







On August 24, 2006, CEI, FirstEnergy, OE, Penn, TE, JCP&L, Met-Ed, Penelec,
      FES and ATSI, as Borrowers, have entered into a new $2.75 billion five-year
      revolving credit facility which replaced the prior $2 billion credit facility.
      FirstEnergy may request an increase in the total commitments available under
      the
      new facility up to a maximum of $3.25 billion . Borrowings under
      the facility are available to each Commitments
      under
      the new facility are available until August 24, 2011, unless the lenders
      agree, at the request of the Borrowers, to two additional one-year extensions.
      Generally, borrowings under the facility must be repaid within 364 days.
      Available amounts for each Borrower are subject to a specified sub-limit, as
      well as applicable regulatory and other limitations. CEI’s
      borrowing
      limit under the facility is $250 million subject to applicable regulatory
      approvals.




Under the revolving credit facility, borrowers may request the issuance of
      letters of credit expiring up to one year from the date of issuance. The stated
      amount of outstanding LOC will count against total commitments available under
      the facility and against the applicable borrower’s borrowing sub-limit. Total
      unused borrowing capability under existing credit facilities and accounts
      receivable financing facilities was $450 million as of September 30,
      2006.




The revolving credit facility contains financial covenants requiring each
      borrower to maintain a consolidated debt to total capitalization ratio of no
      more than 65%, measured at the end of each fiscal quarter. As of
      September 30, 2006, CEI's debt to total capitalization as defined under the
      revolving credit facility was 49%.




The revolving credit facility does not contain provisions that either restrict
      the ability to borrow or accelerate repayment of outstanding advances as a
      result of any change in credit ratings. Pricing is defined in “pricing grids”,
      whereby the cost of funds borrowed under the facility is related to the credit
      ratings of the company borrowing the funds.





CEI’s
      access to the
      capital markets and the costs of financing are dependent on the ratings of
      its
      securities and the securities of FirstEnergy. The ratings outlook from S&P
      on all such securities is stable. The ratings outlook from Moody's and Fitch
      on
      all securities is positive.




In April and May of 2006, pollution control notes that were formerly obligations
      of CEI were refinanced and became obligations of FGCO and NGC. The proceeds
      from
      the refinancings were used to repay a portion of FGCO’s and NGC’s associated
      company notes payable to CEI. CEI redeemed $117.8 million of pollution
      control notes having variable interest rates.




A CEI shelf registration for $550 million of unsecured debt securities was
      declared effective by the SEC on October 31, 2006 and remains
      unused.





*Cash
      Flows from
      Investing Activities*





Net
      cash provided
      from investing activities increased by $61 million in the first nine months
      of
      2006 from the same period last year. The change was primarily due to increased
      loan repayments from associated companies and the absence of net investments
      in
      nuclear decommissioning trust funds due to the intra-system nuclear generation
      asset transfer.





In
      the last quarter
      of 2006, CEI’s capital spending is expected to be approximately $35 million.
      These cash requirements are expected to be satisfied from internal cash and
      short-term credit arrangements. CEI’s capital spending for the period 2006-2010
      is expected to be approximately $622 million of which approximately $129 million
      applies to 2006.





**Off-Balance
      Sheet Arrangements**





Obligations
      not
      included on CEI’s Consolidated Balance Sheet primarily consist of sale and
      leaseback arrangements involving the Bruce Mansfield Plant. As of
      September 30, 2006, the present value of these operating lease commitments,
      net of trust investments, total $95 million.





**Outlook**




The electric industry continues to transition to a more competitive environment
      and all of CEI’s customers can select alternative energy suppliers. CEI
      continues to deliver power to residential homes and businesses through its
      existing distribution system, which remains regulated. Customer rates have
      been
      restructured into separate components to support customer choice. CEI has a
      continuing responsibility to provide power to those customers not choosing
      to
      receive power from an alternative energy supplier subject to certain
      limits.





107








*Regulatory
      Matters*




Regulatory assets are costs which have been authorized by the PUCO and the
      FERC
      for recovery from customers in future periods or for which authorization is
      probable. Without the probability of such authorization, costs currently
      recorded as regulatory assets would have been charged to income as incurred.
      All
      regulatory assets are expected to be recovered under the provisions of CEI’s
      transition plan. CEI’s regulatory assets as of September 30, 2006 and
      December 31, 2005, were $855 million and $862 million,
      respectively.





On
      October 21, 2003,
      the Ohio Companies filed their RSP case with the PUCO. On August 5, 2004, the
      Ohio Companies accepted the RSP as modified and approved by the PUCO in an
      August 4, 2004 Entry on Rehearing, subject to a CBP. The RSP was intended to
      establish generation service rates beginning January 1, 2006, in response to
      the
      PUCO’s concerns about price and supply uncertainty following the end of the Ohio
      Companies' transition plan market development period. In October 2004, the
      OCC
      and NOAC filed appeals with the Supreme Court of Ohio to overturn the original
      June 9, 2004 PUCO order in the proceeding as well as the associated entries
      on
      rehearing. On May 3, 2006, the Supreme Court of Ohio issued an opinion affirming
      the PUCO's order with respect to the approval of the rate stabilization charge,
      approval of the shopping credits, the granting of interest on shopping credit
      incentive deferral amounts, and approval of the Ohio Companies’ financial
      separation plan. It remanded back to the PUCO the matter of ensuring the
      availability of sufficient means for customer participation in the competitive
      marketplace. The RSP contained a provision that permitted the Ohio Companies
      to
      withdraw and terminate the RSP in the event that the PUCO, or the Supreme Court
      of Ohio, rejected all or part of the RSP. In such event, the Ohio Companies
      have
      30 days from the final order or decision to provide notice of termination.
      On
      July 20, 2006 the Ohio Companies filed with the PUCO a Request to Initiate
      a
      Proceeding on Remand. In their Request, the Ohio Companies provided notice
      of
      termination to those provisions of the RSP subject to termination, subject
      to
      being withdrawn, and also set forth a framework for addressing the Supreme
      Court
      of Ohio’s findings on customer participation, requesting the PUCO to initiate a
      proceeding to consider the Ohio Companies’ proposal. If the PUCO approves a
      resolution to the issues raised by the Supreme Court of Ohio that is acceptable
      to the Ohio Companies, the Ohio Companies’ termination will be withdrawn and
      considered to be null and void. Separately, the OCC and NOAC also submitted
      to
      the PUCO on July 20, 2006 a conceptual proposal dealing with the issue raised
      by
      the Supreme Court of Ohio. On July 26, 2006, the PUCO issued an Entry
      acknowledging the July 20, 2006 filings of the Ohio Companies and the OCC and
      NOAC, and giving the Ohio Companies 45 days to file a plan in a new docket
      to
      address the Court’s concern. On September 19, 2006, the PUCO issued an
      Entry granting the Ohio Companies’ motion for extension of time to file the
      remand proposal. The Ohio Companies filed their RSP Remand CBP on
      September 29, 2006. No further proceedings have been scheduled at this
      time.




The Ohio Companies filed an application and stipulation with the PUCO on
      September 9, 2005 seeking approval of the RCP, a supplement to the RSP. On
      November 4, 2005, the Ohio Companies filed a supplemental stipulation with
      the
      PUCO, which constituted an additional component of the RCP filed on
      September 9, 2005. Major provisions of the RCP include:





·
            Maintaining
                the existing level of base distribution rates through April 30, 2009
                for CEI;·
            Deferring
                and
                capitalizing for future recovery (over a 25-year period) with carrying
                charges certain distribution costs to be incurred by all of the Ohio
                Companies during the period January 1, 2006 through December 31,
                2008, not to exceed $150 million in each of the three
                years;·
            Adjusting
                the
                RTC and extended RTC recovery periods and rate levels so that full
                recovery of authorized costs will occur as of December 31, 2010 for
                CEI;·
            Reducing
                the
                deferred shopping incentive balances as of January 1, 2006 by up to
                $85 million for CEI by accelerating the application of its
                accumulated cost of removal regulatory liability; and·
            Deferring
                and
                capitalizing (for recovery over a 25-year period) increased fuel
                costs
                above the amount collected through the Ohio Companies’ fuel recovery
                mechanism.








108







The following table provides CEI’s estimated amortization of regulatory
      transition costs and deferred shopping incentives (including associated carrying
      charges) under the RCP for the period 2006 through 2010:





**Amortization****Period**
            
            **Amortization*****(In
                millions)***2006
            
            $
            962007
            
            
            1132008
            
            
            1302009
            
            
            2112010
            
            
            264**Total
                Amortization**
            
            **$**
            **814**




On January 4, 2006, the PUCO approved, with modifications, the Ohio Companies’
RCP to supplement the RSP to provide customers with more certain rate levels
      than otherwise available under the RSP during the plan period. On
      January 10, 2006, the Ohio Companies filed a Motion for Clarification of
      the PUCO order approving the RCP. The Ohio Companies sought clarity on issues
      related to distribution deferrals, including requirements of the review process,
      timing for recognizing certain deferrals and definitions of the types of
      qualified expenditures. The Ohio Companies also sought confirmation that the
      list of deferrable distribution expenditures originally included in the revised
      stipulation fall within the PUCO order definition of qualified expenditures.
      On
      January 25, 2006, the PUCO issued an Entry on Rehearing granting in part,
      and denying in part, the Ohio Companies’ previous requests and clarifying issues
      referred to above. The PUCO granted the Ohio Companies’ requests to:





·
            Recognize
                fuel
                and distribution deferrals commencing January 1,
                2006;·
            Recognize
                distribution deferrals on a monthly basis prior to review by the
                PUCO
                Staff;·
            Clarify
                that
                the types of distribution expenditures included in the Supplemental
                Stipulation may be deferred; and·
            Clarify
                that
                distribution expenditures do not have to be “accelerated” in order to be
                deferred.




The PUCO approved the Ohio Companies’ methodology for determining distribution
      deferral amounts, but denied the Motion in that the PUCO Staff must verify
      the
      level of distribution expenditures contained in current rates, as opposed to
      simply accepting the amounts contained in the Ohio Companies’ Motion. On
      February 3, 2006, several other parties filed applications for rehearing on
      the PUCO's January 4, 2006 Order. The Ohio Companies responded to the
      applications for rehearing on February 13, 2006. In an Entry on Rehearing
      issued by the PUCO on March 1, 2006, all motions for rehearing were denied.
      Certain of these parties have subsequently filed notices of appeal with the
      Supreme Court of Ohio alleging various errors made by the PUCO in its order
      approving the RCP. The Ohio Companies’ Motion to Intervene in the appeals was
      granted by the Supreme Court on June 8, 2006. The Appellants’ Merit Briefs were
      filed at the Supreme Court on July 5, 2006. The Appellees include the PUCO
      and the Ohio Companies. The Appellees’ Merit Briefs were filed on
      August 24, 2006 and the Appellants’ Reply Briefs were filed on
      September 21 2006. The OCC filed an amicus brief on August 4, 2006,
      which the Ohio Companies moved to strike as improperly filed. The Supreme Court
      denied the Ohio Companies’ motion on October 18, 2006.




On December 30, 2004, CEI filed with the PUCO two applications related to
      the recovery of transmission and ancillary service related costs. The first
      application sought recovery of these costs beginning January 1, 2006. The Ohio
      Companies requested that these costs be recovered through a rider that would
      be
      effective on January 1, 2006 and adjusted each July 1 thereafter. The
      parties reached a settlement agreement that was approved by the PUCO on
      August 31, 2005. The incremental transmission and ancillary service
      revenues recovered from January 1 through June 30, 2006 were approximately
      $23.5 million. That amount included the recovery of a portion of the 2005
      deferred MISO expenses as described below. On April 27, 2006, CEI filed the
      annual update rider to determine revenues ($50 million) from July 2006
      through June 2007. The filed rider went into effect on July 1,
      2006.





109











The second application sought authority to defer costs associated with
      transmission and ancillary service related costs incurred during the period
      October 1, 2003 through December 31, 2005. On May 18, 2005, the
      PUCO granted the accounting authority for the Ohio Companies to defer
      incremental transmission and ancillary service-related charges incurred as
      a
      participant in MISO, but only for those costs incurred during the period
      December 30, 2004 through December 31, 2005. Permission to defer costs
      incurred prior to December 30, 2004 was denied. The PUCO also authorized
      the Ohio Companies to accrue carrying charges on the deferred balances. On
      August 31, 2005, the OCC appealed the PUCO's decision. On
      January 20,
      2006, the OCC sought rehearing of the PUCO’s approval of the recovery of
      deferred costs through the rider during the period January 1, 2006 through
      June 30, 2006. The PUCO denied the OCC's application on February 6,
      2006. On March 23, 2006, the OCC appealed the PUCO's order to the Ohio
      Supreme Court. On March 27, 2006, the OCC filed a motion to consolidate
      this appeal with the deferral appeals discussed above and to postpone oral
      arguments in the deferral appeal until after all briefs are filed in this most
      recent appeal of the rider recovery mechanism. On
      March 20, 2006,
      the Ohio Supreme Court, on its own motion, consolidated the OCC's appeal of
      the
      Ohio Companies' case with a similar case involving Dayton Power & Light
      Company. Oral arguments were heard on May 10, 2006. The Ohio Companies are
      awaiting a final ruling from the Ohio Supreme Court, which is expected before
      the end of 2006.





On
      November 1, 2005,
      FES filed two power sales agreements for approval with the FERC. One power
      sales
      agreement provided for FES to provide the PLR requirements of the Ohio Companies
      at a price equal to the retail generation rates approved by the PUCO for a
      period of three years beginning January 1, 2006. The Ohio Companies will be
      relieved of their obligation to obtain PLR power requirements from FES if the
      Ohio CBP results in a lower price for retail customers. A similar power sales
      agreement between FES and Penn permits Penn to obtain its PLR power requirements
      from FES at a fixed price equal to the retail generation price during 2006.


On
        December 29,
        2005, the FERC issued an order setting the two power sales agreements for
        hearing. The order criticized the Ohio CBP, and required FES to submit
        additional evidence in support of the reasonableness of the prices charged
        in
        the power sales agreements. A pre-hearing conference was held on January
        18,
        2006 to determine the hearing schedule in this case. Under the procedural
        schedule approved in this case, FES expected an initial decision to be issued
        in
        late January 2007. However, on July 14, 2006, the Chief Judge granted the
        joint
        motion of FES and the Trial Staff to appoint a settlement judge in this
        proceeding and the procedural schedule was suspended pending settlement
        discussions among the parties. A settlement conference was held on September
        5,
        2006. FES and the Ohio Companies, Penn, and the PUCO, along
        with other
        parties, reached an agreement to settle the case. The settlement was filed
        with
        the FERC on October 17, 2006, and was unopposed by the remaining parties,
        including the FERC Trial Staff. Initial comments to the settlement are due
        by
        November 6, 2006.
 The
          terms of the
          settlement provide for modification of both the Ohio and Penn power supply
          agreements with FES. Under the Ohio power supply agreement, separate rates
          are
          established for the Ohio Companies’ PLR requirements, special retail contracts
          requirements, wholesale contract requirements, and interruptible buy-through
          retail load requirements. For their PLR and special retail contract
          requirements, the Ohio Companies will pay FES no more than the lower of
          (i) the
          sum of the retail generation charge, the rate stabilization charge, the
          fuel
          recovery mechanism charge, and FES’ actual incremental fuel costs for such
          sales; or (ii) the wholesale price cap. Different wholesale price caps
          are
          imposed for PLR sales, special retail contracts, and wholesale contracts.
          The
          wholesale price for interruptible buy-through retail load requirements
          is
          limited to the actual spot price of power obtained by FES to provide this
          power.
          The Ohio Companies have recognized the estimated additional amount payable
          to
          FES for power supplied during the nine months ended September 30, 2006.
          The
          wholesale rate charged by FES under the Penn power supply agreement will
          be no
          greater than the generation component of charges for retail PLR load in
          Pennsylvania. The FERC is expected to act on this case by the end of the
          fourth
          quarter of 2006.


See Note 11 to the consolidated financial statements for further details
      and a complete discussion of regulatory matters in Ohio.








110





*Environmental
        Matters*
 
 CEI
        accrues environmental liabilities when it is probable that it has an obligation
        for such costs and can reasonably estimate the amount of such costs. Unasserted
        claims are reflected in CEI’s determination of environmental liabilities and are
        accrued in the period that they are both probable and reasonably
        estimable.
 
 *Regulation
        of
        Hazardous Waste-*
  CEI has been named a PRP at waste disposal sites, which may require cleanup
        under the Comprehensive Environmental Response, Compensation and Liability
        Act
        of 1980. Allegations of disposal of hazardous substances at historical sites
        and
        the liability involved are often unsubstantiated and subject to dispute;
        however, federal law provides that all PRPs for a particular site are liable
        on
        a joint and several basis. Therefore, environmental liabilities that are
        considered probable have been recognized on the Consolidated Balance Sheet
        as of
        September 30, 2006, based on estimates of the total costs of cleanup, CEI’s
        proportionate responsibility for such costs and the financial ability of
        other
        unaffiliated entities to pay. Included in Other Noncurrent Liabilities are
        accrued liabilities aggregating approximately $1 million as of September
        30,
        2006.
  See Note 10(B) to the consolidated financial statements for further details
        and a complete discussion of environmental matters.




*Other
      Legal
      Proceedings*




*Power
      Outages and Related
      Litigation-*




On August 14, 2003, various states and parts of southern Canada experienced
      widespread power outages. The outages affected approximately 1.4 million
      customers in FirstEnergy's service area. The U.S. - Canada Power System Outage
      Task Force’s final report in April 2004 on the outages concluded, among other
      things, that the problems leading to the outages began in FirstEnergy’s Ohio
      service area. Specifically,
      the
      final report concluded, among other things, that the initiation of the
      August 14, 2003 power outages resulted from an alleged failure of both
      FirstEnergy and ECAR to assess and understand perceived inadequacies within
      the
      FirstEnergy system; inadequate situational awareness of the developing
      conditions; and a perceived failure to adequately manage tree growth in certain
      transmission rights of way. The Task Force also concluded that there was a
      failure of the interconnected grid's reliability organizations (MISO and PJM)
      to
      provide effective real-time diagnostic support. The final report is publicly
      available through the Department of Energy’s Web site (www.doe.gov). FirstEnergy
      believes that the final report does not provide a complete and comprehensive
      picture of the conditions that contributed to the August 14, 2003 power
      outages and that it does not adequately address the underlying causes of the
      outages. FirstEnergy remains convinced that the outages cannot be explained
      by
      events on any one utility's system. The final report contained 46
“recommendations to prevent or minimize the scope of future blackouts.”
Forty-five of those recommendations related to broad industry or policy matters
      while one, including subparts, related to activities the Task Force recommended
      be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct
      the
      causes of the August 14, 2003 power outages. FirstEnergy implemented
      several initiatives, both prior to and since the August 14, 2003 power
      outages, which were independently verified by NERC as complete in 2004 and
      were
      consistent with these and other recommendations and collectively enhance the
      reliability of its electric system. FirstEnergy’s implementation of these
      recommendations in 2004 included completion of the Task Force recommendations
      that were directed toward FirstEnergy. FirstEnergy is also proceeding with
      the
      implementation of the recommendations that were to be completed subsequent
      to
      2004 and will continue to periodically assess the FERC-ordered Reliability
      Study
      recommendations for forecasted 2009 system conditions, recognizing revised
      load
      forecasts and other changing system conditions which may impact the
      recommendations. Thus far, implementation of the recommendations has not
      required, nor is expected to require, substantial investment in new or material
      upgrades to existing equipment. The FERC or other applicable government agencies
      and reliability coordinators may, however, take a different view as to
      recommended enhancements or may recommend additional enhancements in the future
      as a result of adoption of mandatory reliability standards pursuant to the
      EPACT
      that could require additional material expenditures.







111








FirstEnergy companies also are defending six separate complaint cases before
        the
        PUCO relating to the August 14, 2003 power outages. Two cases were
        originally filed in Ohio State courts but were subsequently dismissed for
        lack
        of subject matter jurisdiction and further appeals were unsuccessful. In
        these
        cases the individual complainants—three in one case and four in the other—sought
        to represent others as part of a class action. The PUCO dismissed the class
        allegations, stating that its rules of practice do not provide for class
        action
        complaints. Three other pending PUCO complaint cases were filed by various
        insurance carriers either in their own name as subrogees or in the name of
        their
        insured. In each of these three cases, the carrier seeks reimbursement from
        various FirstEnergy companies (and, in one case, from PJM, MISO and American
        Electric Power Company, Inc., as well) for claims paid to insureds for damages
        allegedly arising as a result of the loss of power on August 14, 2003. The
        listed insureds in these cases, in many instances, are not customers of any
        FirstEnergy company. The sixth case involves the claim of a non-customer
        seeking
        reimbursement for losses incurred when its store was burglarized on
        August 14, 2003. That case has been dismissed. On
        March 7,
        2006, the PUCO issued a ruling, based on motions filed by the parties,
        applicable to all pending cases. Among its various rulings, the PUCO
        consolidated all of the pending outage cases for hearing; limited the litigation
        to service-related claims by customers of the Ohio operating companies;
        dismissed FirstEnergy as a defendant; ruled that the U.S.-Canada Power System
        Outage Task Force Report was not admissible into evidence; and gave the
        plaintiffs additional time to amend their complaints to otherwise comply
        with
        the PUCO’s underlying order. Also, most
        complainants, along with the FirstEnergy companies, filed applications for
        rehearing with the PUCO over various rulings contained in the March 7, 2006
        order. On April 26, 2006, the PUCO granted rehearing to allow the insurance
        company claimants, as insurers, to prosecute their claims in their name so
        long
        as they also identify the underlying insured entities and the Ohio utilities
        that provide their service. The PUCO denied all other motions for rehearing.
        The
        plaintiffs in each case have since filed an amended complaint and the named
        FirstEnergy companies have answered and also have filed a motion to dismiss
        each
        action. On September 27, 2006, the PUCO dismissed certain parties and claims
        and
        otherwise ordered the complaints to go forward to hearing. The cases have
        been
        set for hearing on October 16, 2007.
  On October 10, 2006, various insurance carriers refiled a complaint in Cuyahoga
        County Common Pleas Court seeking reimbursement for claims paid to numerous
        insureds who allegedly suffered losses as a result of the August 14, 2003
        outages. All of the insureds appear to be non-customers. The plaintiff insurance
        companies are the same claimants in one of the pending PUCO cases. FirstEnergy,
        the Ohio Companies and Penn were served on October 27, 2006, and expect to
        seek summary dismissal of these cases based on the prior court rulings noted
        above. No estimate of potential liability is available for any of these
        cases.
  FirstEnergy is vigorously defending these actions, but cannot predict the
        outcome of any of these proceedings or whether any further regulatory
        proceedings or legal actions may be initiated against the Companies. Although
        unable to predict the impact of these proceedings, if FirstEnergy or its
        subsidiaries were ultimately determined to have legal liability in connection
        with these proceedings, it could have a material adverse effect on FirstEnergy's
        or its subsidiaries' financial condition, results of operations and cash
        flows.
 
 *Other
        Legal
        Matters*
  There are various lawsuits, claims (including claims for asbestos exposure)
        and
        proceedings related to CEI’s normal business operations pending against CEI and
        its subsidiaries. The other potentially material items not otherwise discussed
        above are described below.
  On October 20, 2004, FirstEnergy was notified by the SEC that the
        previously disclosed informal inquiry initiated by the SEC's Division of
        Enforcement in September 2003 relating to the restatements in August 2003
        of
        previously reported results by FirstEnergy and the Ohio Companies, and the
        Davis-Besse extended outage, have become the subject of a formal order of
        investigation. The SEC's formal order of investigation also encompasses issues
        raised during the SEC's examination of FirstEnergy and the Companies under
        the
        now repealed PUHCA. Concurrent with this notification, FirstEnergy received
        a
        subpoena asking for background documents and documents related to the
        restatements and Davis-Besse issues. On December 30, 2004, FirstEnergy
        received a subpoena asking for documents relating to issues raised during
        the
        SEC's PUHCA examination. On August 24, 2005, additional information was
        requested regarding Davis-Besse related disclosures, which FirstEnergy has
        provided. FirstEnergy has cooperated fully with the informal inquiry and
        will
        continue to do so with the formal investigation.





112




The City of Huron filed a complaint against OE with the PUCO challenging
        the
        ability of electric distribution utilities to collect transition charges
        from a
        customer of a newly-formed municipal electric utility. The complaint was
        filed
        on May 28, 2003, and OE timely filed its response on June 30, 2003. In
        a related filing, the Ohio Companies filed for approval with the PUCO of
        a
        tariff that would specifically allow the collection of transition charges
        from
        customers of municipal electric utilities formed after 1998. Both filings
        were
        consolidated for hearing and decision. An adverse ruling could negatively
        affect
        full recovery of transition charges by the utility. Hearings on the matter
        were
        held in August 2005. Initial briefs from all parties were filed on
        September 22, 2005 and reply briefs were filed on October 14, 2005. On
        May 10, 2006, the PUCO issued its Opinion and Order dismissing the City’s
        complaint and approving the related tariffs, thus affirming OE’s entitlement to
        recovery of its transition charges. The City of Huron filed an application
        for
        rehearing of the PUCO’s decision on June 9, 2006 and OE filed a memorandum
        in opposition to that application on June 19, 2006. The PUCO denied the
        City’s application for rehearing on June 28, 2006. The City of Huron has taken
        no further action and the period for filing an appeal has expired.
  If it were ultimately determined that FirstEnergy or its subsidiaries have
        legal
        liability or are otherwise made subject to liability based on the above matters,
        it could have a material adverse effect on FirstEnergy’s or its subsidiaries’
financial condition, results of operations and cash flows.
  See Note 10(C) to the consolidated financial statements for further details
        and a complete discussion of these and other legal proceedings.
 
 **New
        Accounting Standards and Interpretations**
 
 *SAB
                  108 -
                  “Considering the Effects of Prior Year Misstatements when Quantifying
                  Misstatements in Current Year Financial
                  Statements”*
 
 In September 2006, the SEC issued SAB 108, which provides interpretive guidance
        on how registrants should quantify financial statement misstatements. There
        is
        currently diversity in practice, with the two commonly used methods to quantify
        misstatements being the “rollover” method (which primarily focuses on the income
        statement impact of misstatements) and the “iron curtain” method (which focuses
        on the balance sheet impact). SAB 108 requires registrants to use a dual
        approach whereby both of these methods are considered in evaluating the
        materiality of financial statement errors. Prior materiality assessments
        will
        need to be reconsidered using both the rollover and iron curtain methods.
        This
        guidance will be effective for CEI in the fourth quarter of 2006. CEI does
        not expect this Statement to have a material impact on its financial
        statements.





*SFAS
      157 - “Fair
      Value Measurements”*





In September 2006, the FASB issued SFAS 157, that establishes how companies
      should measure fair value when they are required to use a fair value measure
      for
      recognition or disclosure purposes under GAAP. This Statement addresses the
      need
      for increased consistency and comparability in fair value measurements and
      for
      expanded disclosures about fair value measurements. The key changes to current
      practice are: (1) the definition of fair value which focuses on an exit price
      rather than entry price; (2) the methods used to measure fair value such as
      emphasis that fair value is a market-based measurement, not an entity-specific
      measurement, as well as the inclusion of an adjustment for risk, restrictions
      and credit standing; and (3) the expanded disclosures about fair value
      measurements.





This Statement is effective for financial statements issued for fiscal years
      beginning after November 15, 2007, and interim periods within those years.
      CEI is currently evaluating the impact of this Statement on its financial
      statements.





*SFAS
                158 -
                “Employers’ Accounting for Defined Benefit Pension and Other
                Postretirement Plans-an amendment of FASB Statements No. 87, 88,
                106, and
                132(R)”*





In September 2006, the FASB issued SFAS 158, which requires companies to
      recognize a net liability or asset to report the overfunded or underfunded
      status of their defined benefit pension and other postretirement benefit plans
      on their balance sheets and recognize changes in funded status in the year
      in
      which the changes occur through other comprehensive income. The funded status
      to
      be measured is the difference between plan assets at fair value and the benefit
      obligation. This Statement requires that gains and losses and prior service
      costs or credits, net of tax, that arise during the period be recognized as
      a
      component of other comprehensive income and not as components of net periodic
      benefit cost. Additional information should also be disclosed in the notes
      to
      the financial statements about certain effects on net periodic benefit cost
      for
      the next fiscal year that arise from delayed recognition of the gains or losses,
      prior service costs or credits, and transition asset or obligation. Upon the
      initial application of this Statement and subsequently, an employer should
      continue to apply the provisions in Statements 87, 88 and 106 in measuring
      plan
      assets and benefit obligations as of the date of its statement of financial
      position and in determining the amount of net periodic benefit cost. This
      Statement is effective for CEI as of December 31, 2006. CEI is
      currently
      evaluating the impact of this Statement on its financial
      statements.






113





*FIN
      48 -
“Accounting for Uncertainty in Income Taxes - an interpretation of FASB
      Statement No. 109.”*





In
      June 2006, the
      FASB issued FIN 48 which clarifies the accounting for uncertainty in income
      taxes recognized in an enterprise’s financial statements in accordance with FASB
      Statement No. 109, “Accounting for Income Taxes.” This interpretation prescribes
      a recognition threshold and measurement attribute for the financial statement
      recognition and measurement of a tax position taken or expected to be taken
      on a
      tax return. This interpretation also provides guidance on derecognition,
      classification, interest, penalties, accounting in interim periods, disclosure
      and transition. The evaluation of a tax position in accordance with this
      interpretation will be a two-step process. The first step will determine if
      it
      is more likely than not that a tax position will be sustained upon examination
      and should therefore be recognized. The second step will measure a tax position
      that meets the more likely than not recognition threshold to determine the
      amount of benefit to recognize in the financial statements. This interpretation
      is effective for fiscal years beginning after December 15, 2006. CEI is
      currently evaluating the impact of this Statement.








114





**THE
                  TOLEDO EDISON
                  COMPANY****CONSOLIDATED
                  STATEMENTS OF INCOME AND COMPREHENSIVE
                  INCOME****(Unaudited)****Three
                  Months Ended**
              
              **Nine
                  Months Ended****September
                  30,**
              
              **September
                  30,****2006**
              
              **2005**
              
              **2006**
              
              **2005****STATEMENTS
                  OF INCOME**
              
              ***(In
                  thousands)*****REVENUES**
              
              $
              262,837
              
              $
              286,960
              
              $
              706,412
              
              $
              787,824**EXPENSES:**Fuel
              
              
              9,399
              
              
              16,501
              
              
              28,799
              
              
              43,474Purchased
                  power
              
              
              112,389
              
              
              73,144
              
              
              268,468
              
              
              225,600Nuclear
                  operating costs
              
              
              19,252
              
              
              39,207
              
              
              54,450
              
              
              145,059Other
                  operating costs
              
              
              44,253
              
              
              48,164
              
              
              124,396
              
              
              123,823Provision
                  for
                  depreciation
              
              
              8,386
              
              
              18,835
              
              
              24,723
              
              
              48,724Amortization
                  of regulatory assets
              
              
              27,336
              
              
              39,576
              
              
              73,909
              
              
              107,672Deferral
                  of
                  new regulatory assets
              
              
              (15,340
              )
              
              (19,379
              )
              
              (43,186
              )
              
              (41,473
              )General
                  taxes
              
              
              13,406
              
              
              14,159
              
              
              38,590
              
              
              41,960Total
                  expenses
              
              
              219,081
              
              
              230,207
              
              
              570,149
              
              
              694,839**OPERATING
                  INCOME**
              
              
              43,756
              
              
              56,753
              
              
              136,263
              
              
              92,985**OTHER
                  INCOME (EXPENSE):**Investment
                  income
              
              
              9,724
              
              
              22,807
              
              
              28,449
              
              
              39,879Miscellaneous
                  expense
              
              
              (1,933
              )
              
              (2,408
              )
              
              (6,543
              )
              
              (8,810
              )Interest
                  expense
              
              
              (4,940
              )
              
              (6,870
              )
              
              (13,614
              )
              
              (16,847
              )Capitalized
                  interest
              
              
              277
              
              
              372
              
              
              835
              
              
              117Total
                  other
                  income
              
              
              3,128
              
              
              13,901
              
              
              9,127
              
              
              14,339**INCOME
                  BEFORE INCOME TAXES**
              
              
              46,884
              
              
              70,654
              
              
              145,390
              
              
              107,324**INCOME
                  TAXES**
              
              
              17,706
              
              
              28,427
              
              
              54,834
              
              
              57,056**NET
                  INCOME**
              
              
              29,178
              
              
              42,227
              
              
              90,556
              
              
              50,268**PREFERRED
                  STOCK DIVIDEND REQUIREMENTS**
              
              
              1,161
              
              
              1,687
              
              
              3,597
              
              
              6,109**EARNINGS
                  ON COMMON STOCK**
              
              $
              28,017
              
              $
              40,540
              
              $
              86,959
              
              $
              44,159**STATEMENTS
                  OF COMPREHENSIVE INCOME****NET
                  INCOME**
              
              $
              29,178
              
              $
              42,227
              
              $
              90,556
              
              $
              50,268**OTHER
                  COMPREHENSIVE INCOME (LOSS):**Unrealized
                  gain (loss) on available for sale securities
              
              
              1,379
              
              
              (4,511
              )
              
              432
              
              
              (6,695
              )Income
                  tax
                  expense (benefit) related to othercomprehensive
                  income
              
              
              498
              
              
              (1,743
              )
              
              156
              
              
              (2,534
              )Other
                  comprehensive income (loss), net of tax
              
              
              881
              
              
              (2,768
              )
              
              276
              
              
              (4,161
              )**TOTAL
                  COMPREHENSIVE INCOME**
              
              $
              30,059
              
              $
              39,459
              
              $
              90,832
              
              $
              46,107The
                  preceding
                  Notes to Consolidated Financial Statements as they relate to The
                  Toledo
                  Edison Company are an integral part ofthese
                  statements.
   115
  **THE
                    TOLEDO EDISON COMPANY****CONSOLIDATED
                    BALANCE SHEETS****(Unaudited)****September
                    30,**
                
                **December
                    31,****2006**
                
                **2005*****(In
                    thousands)*****ASSETS****CURRENT
                    ASSETS:**Cash
                    and cash
                    equivalents
                
                $
                20
                
                $
                15Receivables-Customers
                
                
                527
                
                
                2,209Associated
                    companies
                
                
                46,252
                
                
                16,311Other
                
                
                3,220
                
                
                6,410Notes
                    receivable from associated companies
                
                
                109,972
                
                
                48,349Prepayments
                    and other
                
                
                1,134
                
                
                1,059161,125
                
                
                74,353**UTILITY
                    PLANT:**In
                    service
                
                
                862,462
                
                
                824,677Less
                    -
                    Accumulated provision for depreciation
                
                
                387,114
                
                
                372,845475,348
                
                
                451,832Construction
                    work in progress
                
                
                33,912
                
                
                33,920509,260
                
                
                485,752**OTHER
                    PROPERTY AND INVESTMENTS:**Long-term
                    notes receivable from associated companies
                
                
                382,668
                
                
                436,178Investment
                    in
                    lessor notes
                
                
                169,523
                
                
                178,798Nuclear
                    plant
                    decommissioning trusts
                
                
                60,826
                
                
                59,209Other
                
                
                1,802
                
                
                1,781614,819
                
                
                675,966**DEFERRED
                    CHARGES AND OTHER ASSETS:**Goodwill
                
                
                500,576
                
                
                501,022Regulatory
                    assets
                
                
                255,869
                
                
                287,095Prepaid
                    pension costs
                
                
                34,903
                
                
                35,566Property
                    taxes
                
                
                18,047
                
                
                18,047Other
                
                
                27,159
                
                
                24,164836,554
                
                
                865,894$
                2,121,758
                
                $
                2,101,965**LIABILITIES
                    AND CAPITALIZATION****CURRENT
                    LIABILITIES:**Currently
                    payable long-term debt
                
                $
                30,000
                
                $
                53,650Accounts
                    payable-Associated
                    companies
                
                
                47,214
                
                
                46,386Other
                
                
                2,946
                
                
                2,672Notes
                    payable
                    to associated companies
                
                
                178,575
                
                
                64,689Accrued
                    taxes
                
                
                52,802
                
                
                49,344Lease
                    market
                    valuation liability
                
                
                24,600
                
                
                24,600Other
                
                
                33,055
                
                
                40,049369,192
                
                
                281,390**CAPITALIZATION:**Common
                    stockholder's equity -Common
                    stock,
                    $5 par value, authorized 60,000,000 shares -39,133,887
                    shares outstanding
                
                
                195,670
                
                
                195,670Other
                    paid-in
                    capital
                
                
                473,924
                
                
                473,638Accumulated
                    other comprehensive income
                
                
                4,966
                
                
                4,690Retained
                    earnings
                
                
                225,613
                
                
                189,428Total
                    common
                    stockholder's equity
                
                
                900,173
                
                
                863,426Preferred
                    stock
                
                
                66,000
                
                
                96,000Long-term
                    debt
                
                
                207,660
                
                
                237,7531,173,833
                
                
                1,197,179**NONCURRENT
                    LIABILITIES:**Accumulated
                    deferred income taxes
                
                
                195,552
                
                
                221,149Accumulated
                    deferred investment tax credits
                
                
                11,217
                
                
                11,824Lease
                    market
                    valuation liability
                
                
                224,950
                
                
                243,400Retirement
                    benefits
                
                
                42,740
                
                
                40,353Asset
                    retirement obligations
                
                
                26,105
                
                
                24,836Deferred
                    revenues - electric service programs
                
                
                25,862
                
                
                32,606Other
                
                
                52,307
                
                
                49,228578,733
                
                
                623,396**COMMITMENTS
                    AND CONTINGENCIES (Note 10)**$
                2,121,758
                
                $
                2,101,965The
                    preceding
                    Notes to Consolidated Financial Statements as they relate to
                    The Toledo
                    Edison Company are anintegral
                    part
                    of these balance sheets.
   116
  **THE
                    TOLEDO EDISON COMPANY****CONSOLIDATED
                    STATEMENTS OF CASH FLOWS****(Unaudited)****Nine
                    Months Ended****September
                    30,****2006**
                
                **2005*****(In
                    thousands)*****CASH
                    FLOWS FROM OPERATING ACTIVITIES:**Net
                    income
                
                $
                90,556
                
                $
                50,268Adjustments
                    to
                    reconcile net income to net cash from operating
                    activities-Provision
                    for
                    depreciation
                
                
                24,723
                
                
                48,724Amortization
                    of regulatory assets
                
                
                73,909
                
                
                107,672Deferral
                    of
                    new regulatory assets
                
                
                (43,186
                )
                
                (41,473
                )Nuclear
                    fuel
                    and capital lease amortization
                
                
                -
                
                
                13,816Deferred
                    rents
                    and lease market valuation liability
                
                
                (27,114
                )
                
                (34,156
                )Deferred
                    income taxes and investment tax credits, net
                
                
                (28,603
                )
                
                (4,605
                )Accrued
                    compensation and retirement benefits
                
                
                2,766
                
                
                3,438Decrease
                    (increase) in operating assets-Receivables
                
                
                (25,069
                )
                
                15,962Materials
                    and
                    supplies
                
                
                -
                
                
                (2,124
                )Prepayments
                    and other current assets
                
                
                (75
                )
                
                (562
                )Increase
                    (decrease) in operating liabilities-Accounts
                    payable
                
                
                1,102
                
                
                (80,586
                )Accrued
                    taxes
                
                
                3,458
                
                
                25,257Accrued
                    interest
                
                
                (709
                )
                
                (565
                )Electric
                    service prepayment programs
                
                
                (6,744
                )
                
                34,653Other
                
                
                1,716
                
                
                (22,999
                )Net
                    cash
                    provided from operating activities
                
                
                66,730
                
                
                112,720**CASH
                    FLOWS FROM FINANCING ACTIVITIES:**New
                    Financing-Long-term
                    debt
                
                
                -
                
                
                45,000Short-term
                    borrowings, net
                
                
                113,886
                
                
                -Redemptions
                    and Repayments-Preferred
                    stock
                
                
                (30,000
                )
                
                (30,000
                )Long-term
                    debt
                
                
                (53,650
                )
                
                (83,754
                )Short-term
                    borrowings, net
                
                
                -
                
                
                (51,327
                )Dividend
                    Payments-Common
                    stock
                
                
                (50,000
                )
                
                (10,000
                )Preferred
                    stock
                
                
                (3,597
                )
                
                (6,109
                )Net
                    cash used
                    for financing activities
                
                
                (23,361
                )
                
                (136,190
                )**CASH
                    FLOWS FROM INVESTING ACTIVITIES:**Property
                    additions
                
                
                (45,661
                )
                
                (50,119
                )Loans
                    to
                    associated companies, net
                
                
                (61,549
                )
                
                (40,491
                )Collection
                    of
                    principal on long-term notes receivable
                
                
                53,766
                
                
                123,546Investments
                    in
                    lessor notes
                
                
                9,275
                
                
                11,927Proceeds
                    from
                    nuclear decommissioning trust fund sales
                
                
                49,744
                
                
                284,968Investments
                    in
                    nuclear decommissioning trust funds
                
                
                (49,922
                )
                
                (306,374
                )Other
                
                
                983
                
                
                13Net
                    cash
                    provided from (used for) investing activities
                
                
                (43,364
                )
                
                23,470Net
                    change in
                    cash and cash equivalents
                
                
                5
                
                
                -Cash
                    and cash
                    equivalents at beginning of period
                
                
                15
                
                
                15Cash
                    and cash
                    equivalents at end of period
                
                $
                20
                
                $
                15The
                    preceding
                    Notes to Consolidated Financial Statements as they relate to
                    The Toledo
                    Edison Company are an integralpart
                    of these
                    statements.
   117











***Report
      of Independent Registered Public Accounting Firm***





























To
      the Stockholder
      and Board of


Directors
      of The
      Toledo Edison Company:





We
      have reviewed the
      accompanying consolidated balance sheet of The Toledo Edison Company and its
      subsidiaries as of September 30, 2006, and the related consolidated statements
      of income and comprehensive income for each of the three-month and nine-month
      periods ended September 30, 2006 and 2005 and the consolidated statements of
      cash flows for the nine-month periods ended September 30, 2006 and 2005. These
      interim financial statements are the responsibility of the Company’s
      management.





We
      conducted our
      review in accordance with the standards of the Public Company Accounting
      Oversight Board (United States). A review of interim financial information
      consists principally of applying analytical procedures and making inquiries
      of
      persons responsible for financial and accounting matters. It is substantially
      less in scope than an audit conducted in accordance with the standards of the
      Public Company Accounting Oversight Board, the objective of which is the
      expression of an opinion regarding the financial statements taken as a whole.
      Accordingly, we do not express such an opinion.





Based
      on our review,
      we are not aware of any material modifications that should be made to the
      accompanying consolidated interim financial statements for them to be in
      conformity with accounting principles generally accepted in the United States
      of
      America.





We
      have previously
      audited, in accordance with the standards of the Public Company Accounting
      Oversight Board (United States), the consolidated balance sheet as of December
      31, 2005, and the related consolidated statements of income, capitalization,
      common stockholder’s equity, preferred stock, cash flows and taxes for the year
      then ended (not presented herein), and in our report [which contained references
      to the Company’s change in its method of accounting for asset retirement
      obligations as of January 1, 2003 as discussed in Note 2(G) and Note 11 to
      those
      consolidated financial statements and the Company’s change in its method of
      accounting for the consolidation of variable interest entities as of December
      31, 2003 as discussed in Note 6 to those consolidated financial statements]
      dated February 27, 2006, we expressed an unqualified opinion on those
      consolidated financial statements. In our opinion, the information set forth
      in
      the accompanying consolidated balance sheet as of December 31, 2005, is fairly
      stated in all material respects in relation to the consolidated balance sheet
      from which it has been derived.





PricewaterhouseCoopers
                LLP
              Cleveland,
                Ohio
              October
                31,
                2006











118





**THE
      TOLEDO
      EDISON COMPANY**





**MANAGEMENT’S
      DISCUSSION AND ANALYSIS OF**


**RESULTS
      OF
      OPERATIONS AND FINANCIAL CONDITION**











TE
      is a wholly owned
      electric utility subsidiary of FirstEnergy. TE conducts business in northwestern
      Ohio, providing regulated electric distribution services. TE also provides
      generation services to those customers electing to retain TE as their power
      supplier. TE’s power supply requirements are provided by FES - an affiliated
      company.





**FirstEnergy
      Intra-System Generation Asset Transfers**




In 2005, the Ohio Companies and Penn entered into certain agreements
      implementing a series of intra-system generation asset transfers that were
      completed in the fourth quarter of 2005. The asset transfers resulted in the
      respective undivided ownership interests of the Ohio Companies and Penn in
      FirstEnergy’s nuclear and non-nuclear generation assets being owned by NGC and
      FGCO, respectively. The generating plant interests transferred did not include
      TE's leasehold interests in certain of the plants that are currently subject
      to
      sale and leaseback arrangements with non-affiliates.




On October 24, 2005, TE completed the intra-system transfer of non-nuclear
      generation assets to FGCO. Prior to the transfer, FGCO, as lessee under a Master
      Facility Lease with the Ohio Companies and Penn, leased, operated and maintained
      the non-nuclear generation assets that it now owns. The asset transfers were
      consummated pursuant to FGCO's purchase option under the Master Facility
      Lease.




On December 16, 2005, TE completed the intra-system transfer of its
      ownership interests in the nuclear generation assets to NGC through a sale
      at
      net book value. FENOC continues to operate and maintain the nuclear generation
      assets.




These transactions were undertaken pursuant to the Ohio Companies’ and Penn’s
      restructuring plans that were approved by the PUCO and the PPUC, respectively,
      under applicable Ohio and Pennsylvania electric utility restructuring
      legislation. Consistent with the restructuring plans, generation assets that
      had
      been owned by the Ohio Companies and Penn were required to be separated from
      the
      regulated delivery business of those companies through transfer to a separate
      corporate entity. The transactions essentially completed the divestitures
      contemplated by the restructuring plans by transferring the ownership interests
      to NGC and FGCO without impacting the operation of the plants.




The
      transfers affect
      TE’s comparative earnings results with reductions in both revenues and expenses.
      Revenues are reduced due to the termination of certain arrangements with FES,
      under which TE previously sold its nuclear-generated KWH to FES and leased
      its
      non-nuclear generation assets to FGCO, a subsidiary of FES. TE’s expenses are
      lower due to the nuclear fuel and operating costs assumed by NGC as well as
      depreciation and property tax expenses assumed by FGCO and NGC related to the
      transferred generating assets. With respect to TE's retained leasehold interests
      in the Bruce Mansfield Plant and Beaver Valley Unit 2, TE has continued the
      generation KWH sales arrangement with FES and its Beaver Valley Unit 2 leased
      capacity sales arrangement with CEI, and continues to be obligated on the
      applicable portion of expenses related to those interests. In addition, TE
      receives interest income on associated company notes receivable from the
      transfer of its generation net assets. FES continues to provide TE’s PLR
      requirements under revised purchased power arrangements covering the three-year
      period beginning January 1, 2006 (see Outlook - Regulatory
      Matters).





119




The effects on TE’s results of operations in the third quarter and nine months
      ended September 30, 2006 compared to the same periods of 2005 from the
      generation asset transfers are summarized in the following table:





**Intra-System
                Generation Asset Transfers -****Income
                Statement Effects**
            
            **Three
                Months**
            
            
            **Nine
                Months****Increase
                (Decrease)**
            
            ***(In
                millions)***Revenues:Non-nuclear
                generating units rent
            (a)
            $
            (4)
            
            
            $
            (11)Nuclear-generated
                KWH sales
            (b)
            
            (38)
            
            
            
            (89)Total
                -
                Revenues Effect
            
            
            (42)
            
            
            
            (100)Expenses:Fuel
                costs -
                nuclear
            (c)
            
            (7)
            
            
            
            (15)Nuclear
                operating costs
            (c)
            
            (21)
            
            
            
            (83)Provision
                for
                depreciation
            (d)
            
            (7)
            
            
            
            (23)General
                taxes
            (e)
            
            (2)
            
            
            
            (5)Total
                -
                Expenses Effect
            
            
            (37)
            
            
            
            (126)Operating
                Income Effect
            
            
            (5)
            
            
            
            26Other
                Income:Interest
                income from notes receivable
            (f)
            
            4
            
            
            
            12Nuclear
                decommissioning trust earnings
            (g)
            
            (17)
            
            
            
            (
                21)Total
                - Other
                Income Effect
            
            
            (13)
            
            
            
            (9)Income
                taxes
            (h)
            
            (7)
            
            
            
            7Net
                Income
                Effect
            
            $
            (11)
            
            
            $
            10(a)
                Elimination of non-nuclear generation assets lease to
                FGCO.(b)
                Reduction
                of nuclear-generated wholesale KWH sales to FES.(c)
                Reduction
                of nuclear fuel and operating costs.(d)
                Reduction
                of depreciation expense and asset retirement obligation accretion
                related
                to generation assets.(e)
                Reduction
                of property tax expense on generation assets.(f)
                Interest
                income on associated company notes receivable from the transfer of
                generation net assets.(g)
                Reduction
                of earnings on nuclear decommissioning trusts.(h)
                Income tax
                effect of the above adjustments.





**Results
      of Operations**


Earnings
        on common
        stock in the third quarter of 2006 decreased to $28 million from
        $41 million in the third quarter of 2005. This decrease resulted primarily
        from lower revenues and lower other income, partially offset by reduced
        operating expenses. Expenses during the third quarter of 2006 included
        $7 million of costs associated with the proposed FERC settlement (see Note
        11) applicable to the first half of 2006. Earnings on common stock in the
        first
        nine months of 2006 increased to $87 million from $44 million in the
        first nine months of 2005. This increase resulted primarily from reduced
        operating expenses and the absence of additional income taxes of
        $17.5 million from the implementation of Ohio tax legislation changes in
        the second quarter of 2005, partially offset by lower revenues and other
        income.
        The earnings results for both periods included the effects of the generation
        asset transfer shown in the table above.





*Revenues*





Revenues
      decreased
      by $24 million or 8.4% in the third quarter of 2006 compared with the same
      period of 2005, primarily due to the generation asset transfer impact displayed
      in the table above. Excluding the effects of the generation asset transfers,
      revenues increased $17 million due to a $44 million increase in generation
      sales
      revenues, a $12 million reduction in customer shopping incentives and a $2
      million increase in other revenues, partially offset by decreased distribution
      revenues of $41 million.





In
      the first nine
      months of 2006, revenues decreased by $81 million or 10.3% compared with the
      same period of 2005, primarily due to the generation asset transfer impact
      displayed in the table above. Excluding the effects of the generation asset
      transfers, revenues increased $18 million due to an $88 million increase in
      generation sales revenues, a $27 million reduction in customer shopping
      incentives and a $3 million increase in other revenues, partially offset by
      a $100 million decrease in distribution revenues.





120





Changes
      in electric
      generation KWH sales and revenues
      in the
      third quarter and first nine months of 2006 from the corresponding periods
      of
      2005 are summarized in the following table.





**Changes
                in Generation KWH Sales**
            
            **Three
                Months**
            
            **Nine
                Months****Increase
                (Decrease)**Electric
                Generation:Retail
            
            
            16.1
            %
            
            14.0
            %Wholesale
            
            
            (63.7
            )%
            
            (59.4
            )%**Net
                Decrease in Generation Sales**
            
            
            **(29.2**
            **)%**
            
            **(25.8**
            **)%**





**Changes
                in Generation Revenues**
            
            **Three
                Months**
            
            **Nine
                Months****Increase
                (Decrease)**
            
            ***(In
                millions)***Retail
                Generation:Residential
            
            $
            24
            
            $
            56Commercial
            
            
            15
            
            
            37Industrial
            
            
            7
            
            
            16Total
                Retail
                Generation
            
            
            46
            
            
            109Wholesale*
            
            
            (2
            )
            
            (21
            )**Net
                Increase in Generation Revenues**
            
            **$**
            **44**
            
            **$**
            **88**




*
      Excludes impact of
      generation asset transfers related to nuclear-generated KWH sales.





Retail
      generation
      revenues increased in all customer sectors in the third quarter of 2006 compared
      to the corresponding quarter of 2005 (as shown in the table above) due to higher
      unit prices and increased KWH sales. The higher unit prices for generation
      reflected the rate stabilization charge and the fuel cost recovery rider that
      both became effective in the first quarter of 2006 under provisions of the
      RSP
      and RCP. The increase in generation KWH sales (residential - 65.4%, commercial
      -
      15.4% and industrial - 2.3%) primarily resulted from decreased customer
      shopping. The decreased shopping resulted from certain alternative energy
      suppliers terminating their supply arrangements with TE's shopping customers
      in
      the first quarter of 2006. Generation services provided by alternative suppliers
      as a percentage of total sales delivered in TE's franchise area decreased in
      all
      customer classes by: residential - 38.4 percentage
      points ,
      commercial - 10.3 percentage points and
      industrial - 2.1 percentage
      points .





In
      the first nine
      months of 2006, retail generation revenues increased from the corresponding
      period of 2005 for the reasons described above. The decreased customer shopping
      resulted in generation KWH sales increases in all customer classes (residential
      - 51.4%, commercial - 14.2% and industrial - 3.3%). Similar to the third quarter
      of 2006, generation services provided by alternative suppliers as a percentage
      of total sales deliveries in TE's franchise area decreased in all customer
      classes by: residential - 32.6 percentage
      points ,
      commercial - 10.1 percentage points and
      industrial - 1.9 percentage
      points .





Lower
      wholesale
      revenues in the third quarter and first nine months of 2006 reflected decreased
      revenues from non-affiliates ($5 million and $13 million, respectively).
      Revenues from associated companies increased $3 million in the third quarter
      of
      2006, but decreased $7 million for the first nine months of 2006. The
      non-affiliated wholesale revenue decreases in 2006 were primarily due to the
      December 2005 cessation in the MSG sales arrangements under TE’s transition
      plan. TE had been required to provide the MSG to non-affiliated alternative
      suppliers.  The
      higher wholesale
      revenues from associated companies in the third quarter of 2006 reflected higher
      unit prices and higher volumes sold than in the third quarter of 2005. The
      lower
      wholesale revenues from associated companies in the first nine months of 2006
      reflected lower unit prices due to this year’s absence of expenses related to
      the Beaver Valley Unit 2 nuclear refueling outage in April 2005, which were
      included as a component of the associated company billing for the 2005
      period.





Changes
      in
      distribution KWH deliveries and revenues
      in the
      third quarter and first nine months of 2006 from the corresponding periods
      of
      2005 are summarized in the following table.








**Changes
                in Distribution KWH Deliveries**
            
            **Three
                Months**
            
            **Nine
                Months****Increase
                (Decrease)**Distribution
                Deliveries:Residential
            
            
            (6.7
            )%
            
            (4.9
            )%Commercial
            
            
            (3.8
            )%
            
            (4.2
            )%Industrial
            
            
            0.1
            %
            
            1.3
            %**Net
                Decrease in Distribution Deliveries**
            
            
            **(2.8**
            **)%**
            
            **(1.8**
            **)%**








121








**Changes
                      in Distribution Revenues**
                  
                  **Three
                      Months**
                  
                  **Nine
                      Months****Increase
                      (Decrease)**
                  
                  ***(In
                      millions)***Residential
                  
                  $
                  (19
                  )
                  $
                  (44
                  )Commercial
                  
                  
                  (17
                  )
                  
                  (46
                  )Industrial
                  
                  
                  (5
                  )
                  
                  (10
                  )**Net
                      Decrease in Distribution Revenues**
                  
                  **$**
                  **(41**
                  **)**
                  **$**
                  **(100**
                  **)**





The
      distribution
      revenue decreases shown in the table above for the third quarter and first
      nine
      months of 2006 compared to the same periods of 2005 primarily reflected lower
      unit prices in all customer sectors and decreased KWH deliveries to residential
      and commercial customers. The lower unit prices resulted from the completion
      of
      the generation-related transition cost recovery under TE’s transition plan in
      2005, partially offset by increased transmission rates to recover MISO costs
      beginning in the first quarter of 2006 (see Outlook - Regulatory Matters).
      The lower
      KWH deliveries to residential and commercial customers in both periods reflected
      the impact of milder weather in the third quarter and the first nine months
      of
      2006 compared to the same periods of 2005. KWH
      deliveries to
      industrial customers increased in both periods of 2006 due to increased sales
      to
      automotive, oil refinery and steel industry customers.





Under
      the Ohio
      transition plan, TE had provided incentives to customers to encourage switching
      to alternative energy providers which reduced TE's revenues. These revenue
      reductions, which were deferred for future recovery and did not affect current
      period earnings, ceased in 2006, thereby increasing revenues in the third
      quarter and first nine months of 2006 by $12 million and $27 million,
      respectively. The deferred shopping incentives (Extended RTC) are currently
      being recovered under the RCP (see Outlook - Regulatory Matters).





*Expenses*





Total
      expenses
      decreased by $11 million and $125 million in the third quarter and the first
      nine months of 2006, respectively, from the same periods of 2005 principally
      due
      to the generation asset transfer effects as shown in the table above. Excluding
      the asset transfer effects, the following table presents changes from the prior
      year by expense category:





**Expenses
                  - Changes**
              
              **Three
                  Months**
              
              **Nine
                  Months****Increase
                  (Decrease)**
              
              ***(In
                  millions)***Fuel
              
              $
              (1
              )
              $
              -Purchased
                  power costs
              
              
              39
              
              
              43Nuclear
                  operating costs
              
              
              1
              
              
              (8
              )Other
                  operating costs
              
              
              (3
              )
              
              1Provision
                  for
                  depreciation
              
              
              (2
              )
              
              -Amortization
                  of regulatory assets
              
              
              (13
              )
              
              (34
              )Deferral
                  of
                  new regulatory assets
              
              
              4
              
              
              (2
              )General
                  taxes
              
              
              1
              
              
              1**Net increase
                  in expenses**
              
              $
              26
              
              $
              1





Lower
      fuel expense
      in the third quarter of 2006 compared to the third quarter of 2005 was
      attributable to the September 2006 turbine outage related to TE’s leasehold
      interest in Mansfield Unit 2. Higher purchased power costs in the third quarter
      of 2006 compared to the third quarter of 2005 primarily reflected an increase
      in
      KWH purchased to meet the higher retail generation sales requirements and higher
      unit prices associated with the new power supply agreement with FES. The higher
      nuclear operating costs associated with TE’s leasehold interest in Beaver Valley
      Unit 2 in the third quarter of 2006 reflected costs related to preparations
      for
      the nuclear refueling outage which began October 2, 2006. Lower other operating
      costs in the third quarter of 2006 primarily reflected the absence of consulting
      fees related to a 2005 investment tax credit claim.





Higher
      purchased
      power costs in the first nine months of 2006 compared to the first nine months
      of 2005 were due to the same reasons as discussed above in the third quarter
      results. Decreased nuclear operating costs in the 2006 nine-month period
      resulted from the absence in 2006 of Beaver Valley Unit 2’s 25-day nuclear
      refueling outage expenses in April 2005. Higher other operating costs primarily
      reflected increased transmission expenses related to MISO Day 2 operations
      that
      began on April 1, 2005, partially offset by the absence of the consulting fees
      in the 2006 period.





122








Excluding
      the
      effects of the generation asset transfers, lower depreciation charges in the
      third quarter of 2006 compared to the same period of 2005 resulted from the
      absence of a one-time adjustment in the third quarter of 2005 for reduced
      amortization periods for expenditures on leased generating plants to conform
      to
      the lease terms.





Lower
      amortization
      of regulatory assets in both periods of 2006 reflected the completion of
      generation-related transition cost recovery under TE’s transition plan,
      partially offset by the amortization of deferred MISO costs that are being
      recovered in 2006. The net change in deferrals of new regulatory assets in
      the
      third quarter and first nine months of 2006 primarily resulted from the
      deferrals of distribution costs ($6 million and $19 million in the third quarter
      and the first nine months of 2006, respectively) and incremental fuel costs
      ($6
      million and $13 million in the third quarter and the first nine months of 2006,
      respectively) that began in 2006 under the RCP. This was partially offset by
      the
      impact of the termination of shopping incentive deferrals in 2006
      ($13 million and $28 million in the third quarter and the first nine months
      of 2006, respectively). The deferral of interest on the unamortized shopping
      incentive balances continues under the RCP. MISO transmission cost deferrals
      decreased by $3 million and $1 million in the third quarter and the first nine
      months of 2006, respectively, compared with the same periods in
      2005.





*Other
      Income*





Other
      income
      decreased $11 million and $5 million in the third quarter and first nine months
      of 2006 compared to the same periods of 2005, primarily due to the effects
      of
      the generation asset transfers. Excluding the asset transfer effects, increases
      of $2 million and $4 million in other income were primarily due to
      lower interest expense in the third quarter and first nine months of 2006,
      respectively, due to redemptions of long-term debt subsequent to the end of
      the
      third quarter of 2005.





*Income
      Taxes*


Income
        taxes
        decreased by $10 million in the third quarter of 2006 and $2 million
        in the first nine months of 2006 compared to the same periods of 2005. Excluding
        the effects of the generation asset transfer, income taxes decreased in the
        third quarter of 2006 by $3 million and in the first nine months of 2006 by
        $9 million. The decrease in the first nine months of 2006 was primarily due
        to the absence in 2006 of $17.5 million of additional income tax expenses
        from
        the implementation of Ohio tax legislation changes in the second quarter
        of 2005
        and the subsequent reduction in the tax rates, partially offset by the effect
        of
        an increase in taxable income.


*Preferred
      Stock
      Dividend Requirements*





Lower
      preferred
      stock dividend requirements in the third quarter of 2006 compared to the same
      quarter of 2005 were the result of $30 million of optional preferred stock
      redemptions in January 2006. Lower preferred stock dividend requirements in
      the
      first nine months of 2006 compared to the corresponding 2005 period resulted
      from $30 million of optional preferred stock redemptions in July 2005 and
      the January 2006 redemption.





**Capital
      Resources and Liquidity**





During
      the remainder
      of 2006, TE expects to meet its contractual obligations with a combination
      of
      cash from operations and short-term credit arrangements.





*Changes
      in Cash
      Position*





As
      of September 30,
      2006, TE had $20,000 of cash and cash equivalents, compared with $15,000 as
      of
      December 31, 2005. The major changes in these balances are summarized below.





123








*Cash
      Flows From
      Operating Activities*





Cash
      provided from
      operating activities during the first nine months of 2006, compared with the
      first nine months of 2005, were as follows:








**Nine
                Months Ended****September
                30,****Operating
                Cash Flows**
            
            **2006**
            
            **2005*****(In
                millions***)Cash
                earnings*
            
            $
            86
            
            $
            140Working
                capital and other
            
            
            (19
            )
            
            (27
            )Net
                cash
                provided from operating activities
            
            $
            67
            
            $
            113*Cash
                earnings are a non-GAAP measure (see reconciliation
                below).





Cash
      earnings (in
      the table above) are not a measure of performance calculated in accordance
      with
      GAAP. TE believes that cash
      earnings is a useful financial measure because it provides investors and
      management with an additional means of evaluating its cash-based operating
      performance. Generally,
      a
      non-GAAP financial measure is a numerical measure of a company’s historical or
      future financial performance, financial position, or cash flows that either
      excludes or includes amounts, or is subject to adjustment that has the effect
      of
      excluding or including amounts, that are not normally excluded or included
      in
      the most directly comparable measure calculated and presented in accordance
      with
      GAAP. In addition, cash earnings (non-GAAP) are not defined under GAAP.
      Management believes presenting this non-GAAP measure provides useful information
      to investors in assessing TE’s operating performance from a cash perspective
      without the effects of material unusual economic events. TE’s management
      frequently references these non-GAAP financial measures in its decision-making,
      using them to facilitate historical and ongoing performance comparisons as
      well
      as comparisons to the performance of peer companies. These non-GAAP measures
      should be considered in addition to, and not as a substitute for, their most
      directly comparable financial measures prepared in accordance with
      GAAP.





**Nine
                Months Ended**
              **September
                30,****Reconciliation
                of Cash Earnings**
            
            **2006**
            
            **2005*****(In
                millions)***Net
                Income
                (GAAP)
            
            $
            90
            
            $
            50Non-Cash
                Charges (Credits):Provision
                for
                depreciation
            
            
            25
            
            
            49Amortization
                of regulatory assets
            
            
            74
            
            
            108Deferral
                of
                new regulatory assets
            
            
            (43
            )
            
            (42
            )Nuclear
                fuel
                and capital lease amortization
            
            
            -
            
            
            14Amortization
                of electric service obligation
            
            
            (7
            )
            
            (3
            )Deferred
                rents
                and lease market valuation liability
            
            
            (27
            )
            
            (34
            )Deferred
                income taxes and investment tax credits, net
            
            
            (29
            )
            
            (5
            )Accrued
                compensation and retirement benefits
            
            
            3
            
            
            3Cash
                earnings
                (Non-GAAP)
            
            $
            86
            
            $
            140




Net cash provided from operating activities decreased by $46 million in the
      first nine months of 2006 from the first nine months of 2005 as a result of
      a
      $54 million decrease in cash earnings described above under “Results of
      Operations” and an $8 million increase from working capital and other
      changes.


*Cash
      Flows From
      Financing Activities*





Net
      cash used for
      financing activities decreased to $23 million in the first nine months of 2006
      from $136 million in the same period of 2005. The decrease resulted primarily
      from a $165 million increase in net short-term borrowings, partially offset
      by a
      $15 million net increase in preferred stock and long-term debt redemptions
      and a
      $40 million increase in common stock dividend payments to FirstEnergy in
      2006.




TE had $110 million of cash and temporary investments (which included short-term
      notes receivable from associated companies) and $179 million of short-term
      indebtedness as of September 30, 2006. TE has authorization from the PUCO to
      incur short-term debt of up to $500 million through the bank facility and
      utility money pool described below. As of September 30, 2006, TE had the
      capability to issue $654 million of additional FMB on the basis of property
      additions and retired bonds under the terms of its mortgage indenture. Based
      upon applicable earnings coverage tests, TE could issue up to $1.0 billion
      of preferred stock (assuming no additional debt was issued) as of
      September 30, 2006.





124







On August 24, 2006, TE, FirstEnergy, OE, Penn, CEI, JCP&L, Met-Ed, Penelec,
      FES and ATSI, as Borrowers, entered into a new $2.75 billion five-year
      revolving credit facility that expires in August 2011 which replaced the prior
      $2 billion credit facility. FirstEnergy may request an increase in the total
      commitments available under the new facility up to a maximum of $3.25 billion.
      Commitments under the new facility are available until August 24, 2011,
      unless the lenders agree, at the request of the Borrowers, to two additional
      one-year extensions. Generally, borrowings under the facility must be repaid
      within 364 days. Available amounts for each Borrower are subject to a specified
      sub-limit, as well as applicable regulatory and other limitations. TE’s
      borrowing limit under the facility is $250 million subject to applicable
      regulatory approval.




Under
      the revolving credit facility, borrowers may request the issuance of LOCs
      expiring up to one year from the date of issuance. The stated amount of
      outstanding LOCs will count against total commitments available under the
      facility and against the applicable borrower’s borrowing sub-limit.




The revolving credit facility contains financial covenants requiring each
      borrower to maintain a consolidated debt to total capitalization ratio of no
      more than 65%, measured at the end of each fiscal quarter. As of
      September 30, 2006, TE's debt to total capitalization, as defined under the
      revolving credit facility, was 30%.




The revolving credit facility does not contain any provisions that either
      restrict TE's ability to borrow or accelerate repayment of outstanding advances
      as a result of any change in its credit ratings. Pricing is defined in “pricing
      grids”, whereby the cost of funds borrowed under the facility is related to TE's
      credit ratings.





TE
      has the ability
      to borrow from its regulated affiliates and FirstEnergy to meet its short-term
      working capital requirements. FESC administers this money pool and tracks
      surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving
      a loan under the money pool agreements must repay the principal, together with
      accrued interest, within 364 days of borrowing the funds. The rate of interest
      is the same for each company receiving a loan from the pool and is based on
      the
      average cost of funds available through the pool. The average interest rate
      for
      borrowings in the first nine months of 2006 was 5.09%.





TE’s
      access to the
      capital markets and the costs of financing are dependent on the ratings of
      its
      securities and the securities of FirstEnergy. The ratings outlook from S&P
      on all securities is stable. The ratings outlook from Moody’s and Fitch on all
      securities is positive.




In April 2006, pollution control notes that were formerly obligations of TE
      were
      refinanced and became obligations of FGCO and NGC. The proceeds from the
      refinancings were used to repay a portion of FGCO’s and NGC’s associated company
      notes payable to TE. With those repayments, TE redeemed pollution control notes
      in the aggregate principal amount of $54 million having variable interest
      rates.




A TE shelf
      registration statement for $300 million of unsecured debt securities was
      declared effective by the SEC on October 31, 2006 and remains
      unused.





*Cash
      Flows From
      Investing Activities*




Net cash used for investing activities was $43 million in the first nine months
      of 2006 compared to net cash of $23 million provided from investing activities
      in the first nine months of 2005. The change was primarily due to a d ecrease
      in the
      collection of principal on long-term notes receivable and an increase in loans
      to associated companies. The decrease in the collection of principal resulted
      from the receipt in April 2006 of $54 million from FGCO and NGC following the
      pollution control notes refinancing discussed above as compared to the receipt
      in May 2005 of a $123 million balloon payment from FGCO for gas-fired combustion
      turbines sold in 2001. The decrease in cash receipts and increase in loans
      were
      partially offset by reduced property additions and net activity for the nuclear
      decommissioning trust funds due to the generation asset transfers.




TE’s capital spending for the last quarter of 2006 is expected to be
      approximately $16 million. These cash requirements are expected to be
      satisfied from a combination of internal cash and short-term credit
      arrangements. TE’s capital spending for the period 2006-2010 is expected to be
      approximately $236 million, of which approximately $62 million applies
      to 2006.





**Off-Balance
      Sheet Arrangements**





Obligations
      not
      included on TE’s Consolidated Balance Sheet primarily consist of sale and
      leaseback arrangements involving the Bruce Mansfield Plant and Beaver Valley
      Unit 2. As of September 30, 2006, the present value of these operating
      lease commitments, net of trust investments, totaled $506 million.





125








**Outlook**




The electric industry continues to transition to a more competitive environment
      and all of TE’s customers can select alternative energy suppliers. TE continues
      to deliver power to residential homes and businesses through its existing
      distribution system, which remains regulated. Customer rates have been
      restructured into separate components to support customer choice. TE has a
      continuing responsibility to provide power to those customers not choosing
      to
      receive power from an alternative energy supplier subject to certain
      limits.





*Regulatory
      Matters*




Regulatory assets are costs which have been authorized by the PUCO and the
      FERC
      for recovery from customers in future periods or for which authorization is
      probable. Without the probability of such authorization, costs currently
      recorded as regulatory assets would have been charged to income as incurred.
      All
      regulatory assets are expected to be recovered under the provisions of TE’s
      regulatory plans. TE’s regulatory assets as of September 30, 2006 and
      December 31, 2005 were $256 million and $287 million,
      respectively.





On
      October 21, 2003,
      the Ohio Companies filed their RSP case with the PUCO. On August 5, 2004, the
      Ohio Companies accepted the RSP as modified and approved by the PUCO in an
      August 4, 2004 Entry on Rehearing, subject to a CBP. The RSP was intended to
      establish generation service rates beginning January 1, 2006, in response to
      the
      PUCO’s concerns about price and supply uncertainty following the end of the Ohio
      Companies' transition plan market development period. In October 2004, the
      OCC
      and NOAC filed appeals with the Supreme Court of Ohio to overturn the original
      June 9, 2004 PUCO order in the proceeding as well as the associated entries
      on
      rehearing. On May 3, 2006, the Supreme Court of Ohio issued an opinion affirming
      the PUCO's order with respect to the approval of the rate stabilization charge,
      approval of the shopping credits, the granting of interest on shopping credit
      incentive deferral amounts, and approval of the Ohio Companies’ financial
      separation plan. It remanded back to the PUCO the matter of ensuring the
      availability of sufficient means for customer participation in the competitive
      marketplace. The RSP contained a provision that permitted the Ohio Companies
      to
      withdraw and terminate the RSP in the event that the PUCO, or the Supreme Court
      of Ohio, rejected all or part of the RSP. In such event, the Ohio Companies
      have
      30 days from the final order or decision to provide notice of termination.
      On
      July 20, 2006 the Ohio Companies filed with the PUCO a Request to Initiate
      a
      Proceeding on Remand. In their Request, the Ohio Companies provided notice
      of
      termination to those provisions of the RSP subject to termination, subject
      to
      being withdrawn, and also set forth a framework for addressing the Supreme
      Court
      of Ohio’s findings on customer participation, requesting the PUCO to initiate a
      proceeding to consider the Ohio Companies’ proposal. If the PUCO approves a
      resolution to the issues raised by the Supreme Court of Ohio that is acceptable
      to the Ohio Companies, the Ohio Companies’ termination will be withdrawn and
      considered to be null and void. Separately, the OCC and NOAC also submitted
      to
      the PUCO on July 20, 2006 a conceptual proposal dealing with the issue raised
      by
      the Supreme Court of Ohio. On July 26, 2006, the PUCO issued an Entry
      acknowledging the July 20, 2006 filings of the Ohio Companies and the OCC and
      NOAC, and giving the Ohio Companies 45 days to file a plan in a new docket
      to
      address the Court’s concern. On September 19, 2006, the PUCO issued an
      Entry granting the Ohio Companies’ Motion for extension of time to file the
      remand proposal. The Ohio Companies filed their RSP Remand CBP on
      September 29, 2006. No further proceedings have been scheduled at this
      time.




The Ohio Companies filed an application and stipulation with the PUCO on
      September 9, 2005 seeking approval of the RCP, a supplement to the RSP. On
      November 4, 2005, the Ohio Companies filed a supplemental stipulation with
      the
      PUCO, which constituted an additional component of the RCP filed on September
      9,
      2005. Major provisions of the RCP include:





·
            Maintaining
                the existing level of base distribution rates through December 31,
                2008 for TE;





·
            Deferring
                and
                capitalizing for future recovery (over a 25-year period) with carrying
                charges certain distribution costs to be incurred by all the Ohio
                Companies during the period January 1, 2006 through December 31,
                2008, not to exceed $150 million in each of the three
                years;





·
            Adjusting
                the
                RTC and extended RTC recovery periods and rate levels so that full
                recovery of authorized costs will occur as of December 31, 2008 for
                TE;





·
            Reducing
                the
                deferred shopping incentive balances as of January 1, 2006 by up to
                $45 million for TE by accelerating the application of its accumulated
                cost of removal regulatory liability;
                and





126








·
            Recovering
                increased fuel costs (compared to a 2002 baseline) of up to $75 million,
                $77 million, and $79 million, in 2006, 2007, and 2008,
                respectively, from all OE and TE distribution and transmission customers
                through a fuel recovery mechanism. OE, TE, and CEI may defer and
                capitalize (for recovery over a 25-year period) increased fuel costs
                above
                the amount collected through the fuel recovery mechanism.




The following table provides TE’s estimated amortization of regulatory
      transition costs and deferred shopping incentives (including associated carrying
      charges) under the RCP for the period 2006 through 2008:





**Amortization**
              **Period**
            
            **Amortization*****(In
                millions)***2006
            
            $
            872007
            
            
            902008
            
            
            112**Total
                Amortization**
            
            **$**
            **289**





On
      January 4, 2006,
      the PUCO approved, with modifications, the Ohio Companies’ RCP to supplement the
      RSP to provide customers with more certain rate levels than otherwise available
      under the RSP during the plan period. On January 10, 2006, the Ohio
      Companies filed a Motion for Clarification of the PUCO order approving the
      RCP.
      The Ohio Companies sought clarity on issues related to distribution deferrals,
      including requirements of the review process, timing for recognizing certain
      deferrals and definitions of the types of qualified expenditures. The Ohio
      Companies also sought confirmation that the list of deferrable distribution
      expenditures originally included in the revised stipulation fall within the
      PUCO
      order definition of qualified expenditures. On January 25, 2006, the PUCO
      issued an Entry on Rehearing granting in part, and denying in part, the Ohio
      Companies’ previous requests and clarifying issues referred to above. The PUCO
      granted the Ohio Companies’ requests to:





·
            Recognize
                fuel
                and distribution deferrals commencing January 1,
                2006;·
            Recognize
                distribution deferrals on a monthly basis prior to review by the
                PUCO
                Staff;·
            Clarify
                that
                the types of distribution expenditures included in the Supplemental
                Stipulation may be deferred; and·
            Clarify
                that
                distribution expenditures do not have to be “accelerated” in order to be
                deferred.





The
      PUCO approved
      the Ohio Companies’ methodology for determining distribution deferral amounts,
      but denied the Motion in that the PUCO Staff must verify the level of
      distribution expenditures contained in current rates, as opposed to simply
      accepting the amounts contained in the Ohio Companies’ Motion. On
      February 3, 2006, several other parties filed applications for rehearing on
      the PUCO's January 4, 2006 Order. The Ohio Companies responded to the
      applications for rehearing on February 13, 2006. In an Entry on Rehearing
      issued by the PUCO on March 1, 2006, all motions for rehearing were denied.
      Certain of these parties have subsequently filed notices of appeal with the
      Supreme Court of Ohio alleging various errors made by the PUCO in its order
      approving the RCP. The Ohio Companies’ Motion to Intervene in the appeals was
      granted by the Supreme Court on June 8, 2006. The Appellant’s Merit Briefs were
      filed at the Supreme Court on July 5, 2006. The Appellees include the PUCO
      and
      the Ohio Companies. The Appellees’ Merit Briefs were filed on August 24,
      2006 and the Appellants’ Reply Briefs were filed on September 21 2006. The
      OCC filed an amicus brief on August 4, 2006, which the Ohio Companies moved
      to strike as improperly filed. The Supreme Court denied the Ohio Companies’
motion on October 18, 2006.




On December 30, 2004, TE filed with the PUCO two applications related to
      the recovery of transmission and ancillary service related costs. The first
      application sought recovery of these costs beginning January 1, 2006. TE
      requested that these costs be recovered through a rider that would be effective
      on January 1, 2006 and adjusted each July 1 thereafter. The parties
      reached a settlement agreement that was approved by the PUCO on August 31,
      2005. The incremental transmission and ancillary service revenues recovered
      from
      January 1 through June 30, 2006 were approximately $6.5 million. That
      amount included the recovery of a portion of the 2005 deferred MISO expenses
      as
      described below. On April 27, 2006, the Ohio Companies filed the annual
      update rider to determine revenues ($139 million) from July 2006 through
      June 2007 ($19 million for TE). The filed rider went into effect on July 1,
      2006.





127








The
      second
      application sought authority to defer costs associated with transmission and
      ancillary service related costs incurred during the period from October 1,
      2003 through December 31, 2005. On May 18, 2005, the PUCO granted the
      accounting authority for the Ohio Companies to defer incremental transmission
      and ancillary service-related charges incurred as a participant in MISO, but
      only for those costs incurred during the period December 30, 2004 through
      December 31, 2005. Permission to defer costs incurred prior to
      December 30, 2004 was denied. The PUCO also authorized the Ohio Companies
      to accrue carrying charges on the deferred balances. On August 31, 2005,
      the OCC appealed the PUCO's decision. On
      January 20,
      2006, the OCC sought rehearing of the PUCO approval of the recovery of deferred
      costs through the rider during the period January 1, 2006 through
      June 30, 2006. The PUCO denied the OCC's application on February 6,
      2006. On March 23, 2006, the OCC appealed the PUCO's order to the Ohio
      Supreme Court. On March 27, 2006, the OCC filed a motion to consolidate
      this appeal with the deferral appeals discussed above and to postpone oral
      arguments in the deferral appeal until after all briefs are filed in this most
      recent appeal of the rider recovery mechanism. On
      March 20, 2006,
      the Ohio Supreme Court, on its own motion, consolidated the OCC's appeal of
      the
      Ohio Companies' case with a similar case involving Dayton Power & Light
      Company. Oral arguments were heard on May 10, 2006. The Ohio Companies are
      awaiting a final ruling from the Ohio Supreme Court, which is
      expected before the end of 2006.





On
      November 1, 2005,
      FES filed two power sales agreements for approval with the FERC. One power
      sales
      agreement provided for FES to provide the PLR requirements of the Ohio Companies
      at a price equal to the retail generation rates approved by the PUCO for a
      period of three years beginning January 1, 2006. The Ohio Companies will be
      relieved of their obligation to obtain PLR power requirements from FES if the
      Ohio CBP results in a lower price for retail customers. A similar power sales
      agreement between FES and Penn permits Penn to obtain its PLR power requirements
      from FES at a fixed price equal to the retail generation price during 2006.


On
        December 29,
        2005, the FERC issued an order setting the two power sales agreements for
        hearing. The order criticized the Ohio CBP, and required FES to submit
        additional evidence in support of the reasonableness of the prices charged
        in
        the power sales agreements. A pre-hearing conference was held on January
        18,
        2006 to determine the hearing schedule in this case. Under the procedural
        schedule approved in this case, FES expected an initial decision to be issued
        in
        late January 2007. However, on July 14, 2006, the Chief Judge granted the
        joint
        motion of FES and the Trial Staff to appoint a settlement judge in this
        proceeding and the procedural schedule was suspended pending settlement
        discussions among the parties. A settlement conference was held on September
        5,
        2006. FES and the Ohio Companies, Penn, and the PUCO, along
        with other
        parties, reached an agreement to settle the case. The settlement was filed
        with
        the FERC on October 17, 2006, and was unopposed by the remaining parties,
        including the FERC Trial Staff. Initial comments to the settlement are due
        by
        November 6, 2006.
 The
          terms of the
          settlement provide for modification of both the Ohio and Penn power supply
          agreements with FES. Under the Ohio power supply agreement, separate rates
          are
          established for the Ohio Companies’ PLR requirements, special retail contracts
          requirements, wholesale contract requirements, and interruptible buy-through
          retail load requirements. For their PLR and special retail contract
          requirements, the Ohio Companies will pay FES no more than the lower of
          (i) the
          sum of the retail generation charge, the rate stabilization charge, the
          fuel
          recovery mechanism charge, and FES’ actual incremental fuel costs for such
          sales; or (ii) the wholesale price cap. Different wholesale price caps
          are
          imposed for PLR sales, special retail contracts, and wholesale contracts.
          The
          wholesale price for interruptible buy-through retail load requirements
          is
          limited to the actual spot price of power obtained by FES to provide this
          power.
          The Ohio Companies have recognized the estimated additional amount payable
          to
          FES for power supplied during the nine months ended September 30, 2006.
          The
          wholesale rate charged by FES under the Penn power supply agreement will
          be no
          greater than the generation component of charges for retail PLR load in
          Pennsylvania. The FERC is expected to act on this case by the end of the
          fourth
          quarter of 2006.




See Note 11 to the consolidated financial statements for further details
      and a complete discussion of regulatory matters in Ohio.





*Environmental
      Matters*





TE
      accrues
      environmental liabilities only when it concludes that it is probable that it
      has
      an obligation for such costs and can reasonably estimate the amount of such
      costs. Unasserted claims are reflected in TE’s determination of environmental
      liabilities and are accrued in the period that they are both probable and
      reasonably estimable.








128







*Regulation
        of
        Hazardous Waste*
  TE
        has been named a PRP at waste
        disposal sites, which may require cleanup under the Comprehensive Environmental
        Response, Compensation and Liability Act of 1980. Allegations of disposal
        of
        hazardous substances at historical sites and the liability involved are often
        unsubstantiated and subject to dispute; however, federal law provides that
        all
        PRPs for a particular site are liable on a joint and several basis. Therefore,
        environmental liabilities that are considered probable have been recognized
        on
        the Consolidated Balance Sheet as of September 30, 2006, based on estimates
        of
        the total costs of cleanup, TE’s proportionate responsibility for such costs and
        the financial ability of other unaffiliated entities to pay. Included in
        Other
        Noncurrent Liabilities are accrued liabilities aggregating approximately
        $0.2 million as of September 30, 2006.
  See Note 10(B) to the consolidated financial statements for further details
        and a complete discussion of environmental matters.
  *Other
        Legal
        Proceedings*




There are various lawsuits, claims (including claims for asbestos exposure)
      and
      proceedings related to TE’s normal business operations pending against TE. The
      other potentially material items not otherwise discussed above are described
      below.





*Power
      Outages
      and Related Litigation-*




On August 14, 2003, various states and parts of southern Canada experienced
      widespread power outages. The outages affected approximately 1.4 million
      customers in FirstEnergy's service area. The U.S. - Canada Power System Outage
      Task Force’s final report in April 2004 on the outages concluded, among other
      things, that the problems leading to the outages began in FirstEnergy’s Ohio
      service area. Specifically,
      the
      final report concluded, among other things, that the initiation of the
      August 14, 2003 power outages resulted from an alleged failure of both
      FirstEnergy and ECAR to assess and understand perceived inadequacies within
      the
      FirstEnergy system; inadequate situational awareness of the developing
      conditions; and a perceived failure to adequately manage tree growth in certain
      transmission rights of way. The Task Force also concluded that there was a
      failure of the interconnected grid's reliability organizations (MISO and PJM)
      to
      provide effective real-time diagnostic support. The final report is publicly
      available through the Department of Energy’s Web site (www.doe.gov). FirstEnergy
      believes that the final report does not provide a complete and comprehensive
      picture of the conditions that contributed to the August 14, 2003 power
      outages and that it does not adequately address the underlying causes of the
      outages. FirstEnergy remains convinced that the outages cannot be explained
      by
      events on any one utility's system. The final report contained 46
“recommendations to prevent or minimize the scope of future blackouts.”
Forty-five of those recommendations related to broad industry or policy matters
      while one, including subparts, related to activities the Task Force recommended
      be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct
      the
      causes of the August 14, 2003 power outages. FirstEnergy implemented
      several initiatives, both prior to and since the August 14, 2003 power
      outages, which were independently verified by NERC as complete in 2004 and
      were
      consistent with these and other recommendations and collectively enhance the
      reliability of its electric system. FirstEnergy’s implementation of these
      recommendations in 2004 included completion of the Task Force recommendations
      that were directed toward FirstEnergy. FirstEnergy is also proceeding with
      the
      implementation of the recommendations that were to be completed subsequent
      to
      2004 and will continue to periodically assess the FERC-ordered Reliability
      Study
      recommendations for forecasted 2009 system conditions, recognizing revised
      load
      forecasts and other changing system conditions which may impact the
      recommendations. Thus far, implementation of the recommendations has not
      required, nor is expected to require, substantial investment in new or material
      upgrades to existing equipment. The FERC or other applicable government agencies
      and reliability coordinators may, however, take a different view as to
      recommended enhancements or may recommend additional enhancements in the future
      as a result of adoption of mandatory reliability standards pursuant to the
      EPACT
      that could require additional material expenditures.







129







FirstEnergy companies also are defending six separate complaint cases before
        the
        PUCO relating to the August 14, 2003 power outages. Two cases were
        originally filed in Ohio State courts but were subsequently dismissed for
        lack
        of subject matter jurisdiction and further appeals were unsuccessful. In
        these
        cases the individual complainants—three in one case and four in the other—sought
        to represent others as part of a class action. The PUCO dismissed the class
        allegations, stating that its rules of practice do not provide for class
        action
        complaints. Three other pending PUCO complaint cases were filed by various
        insurance carriers either in their own name as subrogees or in the name of
        their
        insured. In each of these three cases, the carrier seeks reimbursement from
        various FirstEnergy companies (and, in one case, from PJM, MISO and American
        Electric Power Company, Inc., as well) for claims paid to insureds for damages
        allegedly arising as a result of the loss of power on August 14, 2003. The
        listed insureds in these cases, in many instances, are not customers of any
        FirstEnergy company. The sixth case involves the claim of a non-customer
        seeking
        reimbursement for losses incurred when its store was burglarized on
        August 14, 2003. That case has been dismissed. On
        March 7,
        2006, the PUCO issued a ruling, based on motions filed by the parties,
        applicable to all pending cases. Among its various rulings, the PUCO
        consolidated all of the pending outage cases for hearing; limited the litigation
        to service-related claims by customers of the Ohio operating companies;
        dismissed FirstEnergy as a defendant; ruled that the U.S.-Canada Power System
        Outage Task Force Report was not admissible into evidence; and gave the
        plaintiffs additional time to amend their complaints to otherwise comply
        with
        the PUCO’s underlying order. Also, most
        complainants, along with the FirstEnergy companies, filed applications for
        rehearing with the PUCO over various rulings contained in the March 7, 2006
        order. On April 26, 2006, the PUCO granted rehearing to allow the insurance
        company claimants, as insurers, to prosecute their claims in their name so
        long
        as they also identify the underlying insured entities and the Ohio utilities
        that provide their service. The PUCO denied all other motions for rehearing.
        The
        plaintiffs in each case have since filed an amended complaint and the named
        FirstEnergy companies have answered and also have filed a motion to dismiss
        each
        action. On September 27, 2006, the PUCO dismissed certain parties and claims
        and
        otherwise ordered the complaints to go forward to hearing. The cases have
        been
        set for hearing on October 16, 2007.




On October 10, 2006, various insurance carriers refiled a complaint in Cuyahoga
      County Common Pleas Court seeking reimbursement for claims paid to numerous
      insureds who allegedly suffered losses as a result of the August 14, 2003
      outages. All of the insureds appear to be non-customers. The plaintiff insurance
      companies are the same claimants in one of the pending PUCO cases. FirstEnergy,
      the Ohio Companies and Penn were served on October 27, 2006, and expect to
      seek summary dismissal of these cases based on the prior court rulings noted
      above. No estimate of potential liability is available for any of these
      cases.





FirstEnergy
      is
      vigorously defending these actions, but cannot predict the outcome of any of
      these proceedings or whether any further regulatory proceedings or legal actions
      may be initiated against the Companies. Although unable to predict the impact
      of
      these proceedings, if FirstEnergy or its subsidiaries were ultimately determined
      to have legal liability in connection with these proceedings, it could have
      a
      material adverse effect on FirstEnergy's or its subsidiaries' financial
      condition, results of operations and cash flows.





*Other
      Legal
      Matters-*




On October 20, 2004, FirstEnergy was notified by the SEC that the
      previously disclosed informal inquiry initiated by the SEC's Division of
      Enforcement in September 2003 relating to the restatements in August 2003 of
      previously reported results by FirstEnergy and the Ohio Companies, and the
      Davis-Besse extended outage, have become the subject of a formal order of
      investigation. The SEC's formal order of investigation also encompasses issues
      raised during the SEC's examination of FirstEnergy and the Companies under
      the
      now repealed PUHCA. Concurrent with this notification, FirstEnergy received
      a
      subpoena asking for background documents and documents related to the
      restatements and Davis-Besse issues. On December 30, 2004, FirstEnergy
      received a subpoena asking for documents relating to issues raised during the
      SEC's PUHCA examination. On August 24, 2005, additional information was
      requested regarding Davis-Besse related disclosures, which FirstEnergy has
      provided. FirstEnergy has cooperated fully with the informal inquiry and will
      continue to do so with the formal investigation.




The City of Huron filed a complaint against OE with the PUCO challenging the
      ability of electric distribution utilities to collect transition charges from
      a
      customer of a newly-formed municipal electric utility. The complaint was filed
      on May 28, 2003, and OE timely filed its response on June 30, 2003. In
      a related filing, the Ohio Companies filed for approval with the PUCO of a
      tariff that would specifically allow the collection of transition charges from
      customers of municipal electric utilities formed after 1998. Both filings were
      consolidated for hearing and decision. An adverse ruling could negatively affect
      full recovery of transition charges by the utility. Hearings on the matter
      were
      held in August 2005. Initial briefs from all parties were filed on
      September 22, 2005 and reply briefs were filed on October 14, 2005. On
      May 10, 2006, the PUCO issued its Opinion and Order dismissing the City’s
      complaint and approving the related tariffs, thus affirming OE’s entitlement to
      recovery of its transition charges. The City of Huron filed an application
      for
      rehearing of the PUCO’s decision on June 9, 2006 and OE filed a memorandum
      in opposition to that application on June 19, 2006. The PUCO denied the
      City’s application for rehearing on June 28, 2006. The City of Huron has taken
      no further action and the period for filing an appeal has expired.







130









If
      it were ultimately
      determined that FirstEnergy or its subsidiaries have legal liability or are
      otherwise made subject to liability based on the above matters, it could have
      a
      material adverse effect on FirstEnergy's or its subsidiaries' financial
      condition, results of operations and cash flows.




See Note 10(C) to the consolidated financial statements for further details
      and a complete discussion of these and other legal proceedings.





**New
      Accounting Standards and Interpretations**





*SAB
                108 -
                “Considering the Effects of Prior Year Misstatements when Quantifying
                Misstatements in Current Year Financial
                Statements”*





In
      September 2006,
      the SEC issued SAB 108, which provides interpretive guidance on how registrants
      should quantify financial statement misstatements. There is currently diversity
      in practice, with the two commonly used methods to quantify misstatements being
      the “rollover” method (which primarily focuses on the income statement impact of
      misstatements) and the “iron curtain” method (which focuses on the balance sheet
      impact). SAB 108 requires registrants to use a dual approach whereby both of
      these methods are considered in evaluating the materiality of financial
      statement errors. Prior materiality assessments will need to be reconsidered
      using both the rollover and iron curtain methods. This guidance will be
      effective for TE in the fourth quarter of 2006. TE does not expect
      this Statement to have a material impact on its financial
      statements.





*SFAS
      157 - “Fair
      Value Measurements”*





In
      September 2006,
      the FASB issued SFAS 157 that establishes how companies should measure fair
      value when they are required to use a fair value measure for recognition or
      disclosure purposes under GAAP. This Statement addresses the need for increased
      consistency and comparability in fair value measurements and for expanded
      disclosures about fair value measurements. The key changes to current practice
      are: (1) the definition of fair value which focuses on an exit price rather
      than
      entry price; (2) the methods used to measure fair value such as emphasis that
      fair value is a market-based measurement, not an entity-specific measurement,
      as
      well as the inclusion of an adjustment for risk, restrictions and credit
      standing; and (3) the expanded disclosures about fair value
      measurements.





This
      Statement is
      effective for financial statements issued for fiscal years beginning after
      November 15, 2007, and interim periods within those years. TE is currently
      evaluating the impact of this Statement on its financial statements.





*SFAS
                158 -
                “Employers’ Accounting for Defined Benefit Pension and Other
                Postretirement Plans-an amendment of FASB Statements No. 87, 88,
                106, and
                132(R)”*





In
      September 2006,
      the FASB issued SFAS 158, which requires companies to recognize a net liability
      or asset to report the overfunded or underfunded status of their defined benefit
      pension and other postretirement benefit plans on their balance sheets and
      recognize changes in funded status in the year in which the changes occur
      through other comprehensive income. The funded status to be measured is the
      difference between plan assets at fair value and the benefit obligation. This
      Statement requires that gains and losses and prior service costs or credits,
      net
      of tax, that arise during the period be recognized as a component of other
      comprehensive income and not as components of net periodic benefit cost.
      Additional information should also be disclosed in the notes to the financial
      statements about certain effects on net periodic benefit cost for the next
      fiscal year that arise from delayed recognition of the gains or losses, prior
      service costs or credits, and transition asset or obligation. Upon the initial
      application of this Statement and subsequently, an employer should continue
      to
      apply the provisions in Statements 87, 88 and 106 in measuring plan assets
      and
      benefit obligations as of the date of its statement of financial position and
      in
      determining the amount of net periodic benefit cost. This Statement is effective
      for TE as of December 31, 2006. TE is currently
      evaluating the impact of this Statement on its financial
      statements.





*FIN
      48 -
“Accounting for Uncertainty in Income Taxes - an interpretation of FASB
      Statement No. 109.”*





In
      June 2006, the
      FASB issued FIN 48 which clarifies the accounting for uncertainty in income
      taxes recognized in an enterprise’s financial statements in accordance with FASB
      Statement No. 109, “Accounting for Income Taxes.” This interpretation prescribes
      a recognition threshold and measurement attribute for the financial statement
      recognition and measurement of a tax position taken or expected to be taken
      on a
      tax return. This interpretation also provides guidance on derecognition,
      classification, interest, penalties, accounting in interim periods, disclosure
      and transition. The evaluation of a tax position in accordance with this
      interpretation will be a two-step process. The first step will determine if
      it
      is more likely than not that a tax position will be sustained upon examination
      and should therefore be recognized. The second step will measure a tax position
      that meets the more likely than not recognition threshold to determine the
      amount of benefit to recognize in the financial statements. This interpretation
      is effective for fiscal years beginning after December 15, 2006. TE is currently
      evaluating the impact of this Statement.





131




**PENNSYLVANIA
                  POWER
                  COMPANY****CONSOLIDATED
                  STATEMENTS OF
                  INCOME****(Unaudited)****Three
                  Months Ended**
              
              **Nine
                  Months Ended****September
                  30,**
              
              **September
                  30,****2006**
              
              **2005**
              
              **2006**
              
              **2005*****(In
                  thousands)*****REVENUES**
              
              $
              88,700
              
              $
              145,540
              
              $
              252,069
              
              $
              414,306**EXPENSES:**Fuel
              
              
              -
              
              
              6,205
              
              
              -
              
              
              17,351Purchased
                  power
              
              
              60,490
              
              
              42,242
              
              
              171,759
              
              
              131,948Nuclear
                  operating costs
              
              
              -
              
              
              16,997
              
              
              -
              
              
              56,710Other
                  operating costs
              
              
              16,448
              
              
              19,030
              
              
              44,776
              
              
              48,541Provision
                  for
                  depreciation
              
              
              2,383
              
              
              3,847
              
              
              6,509
              
              
              11,351Amortization
                  of regulatory assets
              
              
              -
              
              
              9,784
              
              
              3,411
              
              
              29,499General
                  taxes
              
              
              6,098
              
              
              6,836
              
              
              17,602
              
              
              19,752Total
                  expenses
              
              
              85,419
              
              
              104,941
              
              
              244,057
              
              
              315,152**OPERATING
                  INCOME**
              
              
              3,281
              
              
              40,599
              
              
              8,012
              
              
              99,154**OTHER
                  INCOME (EXPENSE):**Miscellaneous
                  income
              
              
              3,468
              
              
              698
              
              
              10,319
              
              
              475Interest
                  expense
              
              
              (1,461
              )
              
              (2,371
              )
              
              (6,823
              )
              
              (7,477
              )Capitalized
                  interest
              
              
              62
              
              
              1,665
              
              
              144
              
              
              4,508Total
                  other
                  income (expense)
              
              
              2,069
              
              
              (8
              )
              
              3,640
              
              
              (2,494
              )**INCOME
                  BEFORE INCOME TAXES**
              
              
              5,350
              
              
              40,591
              
              
              11,652
              
              
              96,660**INCOME
                  TAXES**
              
              
              2,117
              
              
              17,551
              
              
              4,924
              
              
              42,907**NET
                  INCOME**
              
              
              3,233
              
              
              23,040
              
              
              6,728
              
              
              53,753**PREFERRED
                  STOCK DIVIDEND REQUIREMENTS**
              
              
              156
              
              
              156
              
              
              467
              
              
              1,534**EARNINGS
                  ON COMMON STOCK**
              
              $
              3,077
              
              $
              22,884
              
              $
              6,261
              
              $
              52,219The
                  preceding
                  Notes to Consolidated Financial Statements as they relate to Pennsylvania
                  Power Company are an integral partof
                  these
                  statements.
   132
  **PENNSYLVANIA
                    POWER COMPANY****CONSOLIDATED
                    BALANCE SHEETS****(Unaudited)****September
                    30,**
                
                **December
                    31,****2006**
                
                **2005*****(In
                    thousands)*****ASSETS****CURRENT
                    ASSETS:**Cash
                    and cash
                    equivalents
                
                $
                36
                
                $
                24Receivables
                    -Customers
                    (less accumulated provisions of $1,135,000 and $1,087,000,respectively,
                    for uncollectible accounts)
                
                
                37,978
                
                
                44,555Associated
                    companies
                
                
                86,656
                
                
                115,441Other
                
                
                1,778
                
                
                2,889Notes
                    receivable from associated companies
                
                
                1,851
                
                
                1,699Restricted
                    cash
                
                
                -
                
                
                78,248Prepayments
                    and other
                
                
                12,744
                
                
                8,747141,043
                
                
                251,603**UTILITY
                    PLANT:**In
                    service
                
                
                371,575
                
                
                359,069Less
                    -
                    Accumulated provision for depreciation
                
                
                132,749
                
                
                129,118238,826
                
                
                229,951Construction
                    work in progress
                
                
                3,865
                
                
                3,775242,691
                
                
                233,726**OTHER
                    PROPERTY AND INVESTMENTS:**Long-term
                    notes receivable from associated companies
                
                
                275,924
                
                
                283,248Other
                
                
                350
                
                
                351276,274
                
                
                283,599**DEFERRED
                    CHARGES AND OTHER ASSETS:**Prepaid
                    pension costs
                
                
                43,462
                
                
                42,243Other
                
                
                1,794
                
                
                3,82945,256
                
                
                46,072$
                705,264
                
                $
                815,000**LIABILITIES
                    AND CAPITALIZATION****CURRENT
                    LIABILITIES:**Currently
                    payable long-term debt
                
                $
                15,474
                
                $
                69,524Short-term
                    borrowings -Associated
                    companies
                
                
                1,607
                
                
                12,703Other
                
                
                19,000
                
                
                -Accounts
                    payable -Associated
                    companies
                
                
                18,194
                
                
                73,444Other
                
                
                1,581
                
                
                1,828Accrued
                    taxes
                
                
                20,629
                
                
                28,632Accrued
                    interest
                
                
                1,075
                
                
                1,877Other
                
                
                7,484
                
                
                8,08685,044
                
                
                196,094**CAPITALIZATION:**Common
                    stockholder's equityCommon
                    stock,
                    $30 par value, authorized 6,500,000 shares-6,290,000
                    shares outstanding
                
                
                188,700
                
                
                188,700Other
                    paid-in
                    capital
                
                
                71,136
                
                
                71,136Retained
                    earnings
                
                
                43,268
                
                
                37,097Total
                    common
                    stockholder's equity
                
                
                303,104
                
                
                296,933Preferred
                    stock
                
                
                14,105
                
                
                14,105Long-term
                    debt
                    and other long-term obligations
                
                
                123,344
                
                
                130,677440,553
                
                
                441,715**NONCURRENT
                    LIABILITIES:**Accumulated
                    deferred income taxes
                
                
                63,321
                
                
                66,576Retirement
                    benefits
                
                
                47,268
                
                
                45,967Regulatory
                    liabilities
                
                
                63,679
                
                
                58,637Other
                
                
                5,399
                
                
                6,011179,667
                
                
                177,191**COMMITMENTS
                    AND CONTINGENCIES (Note 10)**$
                705,264
                
                $
                815,000The
                    preceding
                    Notes to Consolidated Financial Statements as they relate to
                    Pennsylvania
                    Power Company are an integralpart
                    of these
                    balance sheets.
   133
  **PENNSYLVANIA
                    POWER COMPANY****CONSOLIDATED
                    STATEMENTS OF CASH FLOWS****(Unaudited)****Nine
                    Months Ended****September
                    30,****2006**
                
                **2005*****(In
                    thousands)*****CASH
                    FLOWS FROM OPERATING ACTIVITIES:**Net
                    income
                
                $
                6,728
                
                $
                53,753Adjustments
                    to
                    reconcile net income to net cash from operating activities
                    -Provision
                    for
                    depreciation
                
                
                6,509
                
                
                11,351Amortization
                    of regulatory assets
                
                
                3,411
                
                
                29,499Nuclear
                    fuel
                    and other amortization
                
                
                -
                
                
                12,912Deferred
                    income taxes and investment tax credits, net
                
                
                (2,809
                )
                
                (7,567
                )Decrease
                    (increase) in operating assets -Receivables
                
                
                36,473
                
                
                15,141Materials
                    and
                    supplies
                
                
                -
                
                
                (51
                )Prepayments
                    and other current assets
                
                
                (3,997
                )
                
                (3,186
                )Increase
                    (decrease) in operating liabilities -Accounts
                    payable
                
                
                (55,497
                )
                
                (29,056
                )Accrued
                    taxes
                
                
                (8,003
                )
                
                12,108Accrued
                    interest
                
                
                (802
                )
                
                (237
                )Other
                
                
                2,012
                
                
                1,027Net
                    cash
                    provided from (used for) operating activities
                
                
                (15,975
                )
                
                95,694**CASH
                    FLOWS FROM FINANCING ACTIVITIES:**New
                    Financing
                    -Short-term
                    borrowings, net
                
                
                7,904
                
                
                22,969Redemptions
                    and Repayments -Preferred
                    stock
                
                
                -
                
                
                (37,750
                )Long-term
                    debt
                
                
                (61,899
                )
                
                (849
                )Dividend
                    Payments -Common
                    stock
                
                
                -
                
                
                (8,000
                )Preferred
                    stock
                
                
                (467
                )
                
                (1,534
                )Net
                    cash used
                    for financing activities
                
                
                (54,462
                )
                
                (25,164
                )**CASH
                    FLOWS FROM INVESTING ACTIVITIES:**Property
                    additions
                
                
                (14,811
                )
                
                (69,630
                )Proceeds
                    from
                    nuclear decommissioning trust fund sales
                
                
                -
                
                
                57,003Investments
                    in
                    nuclear decommissioning trust funds
                
                
                -
                
                
                (58,199
                )Loan
                    repayments from associated companies
                
                
                7,172
                
                
                (14
                )Cash
                    investments
                
                
                78,248
                
                
                -Other
                
                
                (160
                )
                
                296Net
                    cash
                    provided from (used for) investing activities
                
                
                70,449
                
                
                (70,544
                )Net
                    increase
                    (decrease) in cash and cash equivalents
                
                
                12
                
                
                (14
                )Cash
                    and cash
                    equivalents at beginning of period
                
                
                24
                
                
                38Cash
                    and cash
                    equivalents at end of period
                
                $
                36
                
                $
                24The
                    preceding
                    Notes to Consolidated Financial Statements as they relate to
                    Pennsylvania
                    Power Company are an integralpart
                    of these
                    statements.








134











***Report
      of Independent Registered Public Accounting Firm***





























To
      the Stockholder
      and Board of


Directors
      of
      Pennsylvania Power Company:





We
      have reviewed the
      accompanying consolidated balance sheet of Pennsylvania Power Company and its
      subsidiaries as of September 30, 2006, and the related consolidated statement
      of
      income for each of the three-month and nine-month periods ended September 30,
      2006 and 2005 and the consolidated statements of cash flows for the nine-month
      periods ended September 30, 2006 and 2005. These interim financial statements
      are the responsibility of the Company’s management.





We
      conducted our
      review in accordance with the standards of the Public Company Accounting
      Oversight Board (United States). A review of interim financial information
      consists principally of applying analytical procedures and making inquiries
      of
      persons responsible for financial and accounting matters. It is substantially
      less in scope than an audit conducted in accordance with the standards of the
      Public Company Accounting Oversight Board, the objective of which is the
      expression of an opinion regarding the financial statements taken as a whole.
      Accordingly, we do not express such an opinion.





Based
      on our review,
      we are not aware of any material modifications that should be made to the
      accompanying consolidated interim financial statements for them to be in
      conformity with accounting principles generally accepted in the United States
      of
      America.





We
      have previously
      audited, in accordance with the standards of the Public Company Accounting
      Oversight Board (United States), the consolidated balance sheet as of December
      31, 2005, and the related consolidated statements of income, capitalization,
      common stockholder’s equity, preferred stock, cash flows and taxes for the year
      then ended (not presented herein), and in our report [which contained references
      to the Company’s change in its method of accounting for asset retirement
      obligations as of January 1, 2003 as discussed in Note 2(G) and Note 8 to those
      consolidated financial statements] dated February 27, 2006, we expressed an
      unqualified opinion on those consolidated financial statements. In our opinion,
      the information set forth in the accompanying consolidated balance sheet as
      of
      December 31, 2005, is fairly stated in all material respects in relation to
      the
      consolidated balance sheet from which it has been derived.





PricewaterhouseCoopers
                LLP
              Cleveland,
                Ohio
              October
                31,
                2006











135





**PENNSYLVANIA
      POWER COMPANY**





**MANAGEMENT’S
      DISCUSSION AND ANALYSIS OF**


**RESULTS
      OF
      OPERATIONS AND FINANCIAL CONDITION**











Penn
      is a wholly
      owned, electric utility subsidiary of OE. Penn conducts business in western
      Pennsylvania, providing regulated electric distribution services. Penn also
      provides generation services to those customers electing to retain Penn as
      their
      power supplier. Penn's rate restructuring plan and its associated transition
      charge revenue recovery was completed in 2005. Its power supply requirements
      are
      provided by FES - an affiliated company.





**FirstEnergy
      Intra-System Generation Asset Transfers**





On
      May 13,
      2005, Penn, and on May 18, 2005, the Ohio Companies, entered into certain
      agreements implementing a series of intra-system generation asset transfers
      that
      were completed in the fourth quarter of 2005. The asset transfers resulted
      in
      the respective undivided ownership interests of the Ohio Companies and Penn
      in
      FirstEnergy’s nuclear and non-nuclear generation assets being owned by NGC and
      FGCO, respectively.




On October 24, 2005, the Ohio Companies and Penn completed the intra-system
      transfer of non-nuclear generation assets to FGCO. Prior to the transfer, FGCO,
      as lessee under a Master Facility Lease with the Ohio Companies and Penn,
      leased, operated and maintained the non-nuclear generation assets that it now
      owns. The asset transfers were consummated pursuant to FGCO's purchase option
      under the Master Facility Lease.




On December 16, 2005, the Ohio Companies and Penn completed the intra-system
      transfer of their respective ownership in the nuclear generation assets to
      NGC
      through, in the case of OE and Penn, an asset spin-off by way of dividend.
      FENOC
      continues to operate and maintain the nuclear generation assets.




These transactions were pursuant to the Ohio Companies’ and Penn’s restructuring
      plans that were approved by the PUCO and the PPUC, respectively, under
      applicable Ohio and Pennsylvania electric utility restructuring legislation.
      Consistent with the restructuring plans, generation assets that had been owned
      by the Ohio Companies and Penn were required to be separated from the regulated
      delivery business of those companies through transfer to a separate corporate
      entity. The transactions essentially completed the divestitures contemplated
      by
      the restructuring plans by transferring the ownership interests to NGC and
      FGCO
      without impacting the operation of the plants.





The
      transfers will
      affect Penn’s comparative earnings results with reductions in both revenues and
      expenses. Revenues are reduced due to the termination of certain arrangements
      with FES, under which Penn previously sold its nuclear-generated KWH to FES
      and
      leased its non-nuclear generation assets to FGCO, a subsidiary of FES. Penn’s
      expenses are lower due to the nuclear fuel and operating costs assumed by NGC
      as
      well as depreciation and property tax expenses assumed by FGCO and NGC related
      to the transferred generating assets. In addition, Penn receives interest income
      on associated company notes receivable from the transfer of its generation
      net
      assets. FES will continue to provide Penn’s PLR requirements under revised
      purchased power arrangements during 2006 (see Outlook -- Regulatory
      Matters).





136




The effects on Penn’s results of operations in the third quarter and nine months
      ended September 30, 2006 compared to the same periods of 2005 from the
      generation asset transfers are summarized in the following table:





**Intra-System
                  Generation Asset Transfers****Income
                  Statement Effects**
              
              **Three
                  Months**
              
              
              **Nine
                  Months****Increase
                  (Decrease)**
              
              ***(In
                  millions)***Revenues:Non-nuclear
                  generating units rent
              (a)
              $
              (5)
              
              
              $
              (15)Nuclear
                  generated KWH sales
              (b)
              
              (42)
              
              
              
              (118)Total
                  -
                  Revenues Effect
              
              
              (47)
              
              
              
              (133)Expenses:Fuel
                  costs -
                  nuclear
              (c)
              
              (6)
              
              
              
              (17)Nuclear
                  operating costs
              (c)
              
              (17)
              
              
              
              (57)Provision
                  for
                  depreciation
              (d)
              
              (1)
              
              
              
              (4)General
                  taxes
              (e)
              
              (1)
              
              
              
              (1)Total
                  -
                  Expenses Effect
              
              
              (25)
              
              
              
              (79)Operating
                  Income Effect
              
              
              (22)
              
              
              
              (54)Other
                  income:Interest
                  income from notes receivable
              (f)
              
              2
              
              
              
              7Capitalized
                  interest
              (g)
              
              (1)
              
              
              
              (4)Total
                  - Other
                  Income Effect
              
              
              1
              
              
              
              3Income
                  taxes
              (h)
              
              (9)
              
              
              
              (21)Net
                  Income
                  Effect
              
              $
              (12)
              
              
              $
              (30)(a)
                  Elimination of non-nuclear generation assets lease to FGCO.
                (b)
                  Reduction
                  of nuclear generated wholesale KWH sales to FES.(c)
                  Reduction
                  of nuclear fuel and operating costs.(d)
                  Reduction
                  of depreciation expense and asset retirement obligation accretion
                  related
                  to generation assets.(e)
                  Reduction
                  of property tax expense on generation assets.(f)
                  Interest
                  income on associated company notes receivable from the transfer
                  of
                  generation net assets.(g)
                  Reduction
                  of allowance for borrowed funds used during construction on nuclear
                  capital expenditures.(h)
                  Income tax
                  effect of the above adjustments.





**Results
      of Operations**





Earnings
      on common
      stock in the third quarter of 2006 decreased to $3 million from $23 million
      in the third quarter of 2005. During the first nine months of 2006 earnings
      on
      common stock decreased to $6 million from $52 million in the first
      nine months of 2005. The lower earnings in both periods of 2006 resulted
      principally from the generation asset transfer effects shown in the table above,
      lower revenues and higher purchased power costs, partially offset by a reduction
      in regulatory asset amortization due to the completion of Penn’s rate
      restructuring plan in 2005.





*Revenues*





Revenues
      decreased
      by $57 million, or 39%, and $162 million, or 39%, in the third quarter and
      the
      first nine months of 2006, respectively, as compared with the same periods
      of
      2005, primarily due to the generation asset transfer impact summarized in the
      table above. Excluding the effects of the asset transfer, revenues decreased
      by
      $10 million, or 7.0% and $29 million, or 7.1%, in the third quarter
      and the first nine months of 2006, respectively. These decreases resulted from
      lower distribution revenues ($9 million and $26 million, respectively)
      primarily reflecting the completion of Penn's generation-related transition
      cost
      recovery under Penn’s rate restructuring plan and lower wholesale revenues
      ($6 million and $18 million, respectively) resulting from the
      termination of a wholesale sales agreement with a non-affiliate in December
      2005. Partially offsetting these decreases were increases in retail generation
      revenues of $5 million in the third quarter and $15 million in the
      first nine months of 2006, primarily from higher composite unit prices
      associated with a 5% rate increase for generation permitted by the PPUC for
      all
      customer classes.





137








Distribution
      KWH
      deliveries were lower to residential customers in the third quarter and to
      both
      residential and commercial sectors in the first nine months of 2006 due to
      the
      impact of milder weather conditions compared to the same periods of 2005. Higher
      KWH deliveries to industrial customers in both periods of 2006 were largely
      due
      to increased demand from the steel sector.





Changes
      in KWH sales
      by customer class in the third quarter and the first nine months of 2006 from
      the same periods of 2005 are summarized in the following tables:





**Changes
                in KWH Sales**
            
            **Three
                Months**
            
            **Nine
                Months****Increase
                (Decrease)**Retail
                Electric Generation:Residential
            
            
            (1.4)%
            
            
            (3.6)%Commercial
            
            
            0.8
                %
            
            
            (1.4)%Industrial
            
            
            4.8
                %
            
            
            6.4
                %**Total
                Retail Electric Generation Sales**
            
            
            **1.4
                %**
            
            
            **0.5
                %**Distribution
                Deliveries:Residential
            
            
            (1.7)%
            
            
            (3.8)%Commercial
            
            
            0.8
                %
            
            
            (1.5)%Industrial
            
            
            4.8
                %
            
            
            6.4
                %**Total
                Distribution Deliveries**
            
            
            **1.3
                %**
            
            
            **0.4
                %**





*Expenses*





Total
      expenses
      decreased by $20 million in the third quarter and $71 million in the first
      nine
      months of 2006 from the same periods of 2005 principally due to the generation
      asset transfer impact as shown previously. Excluding the asset transfer effects,
      the following table presents changes from the prior year by expense
      category:





**Expenses
                - Changes**
            
            **Three
                Months**
            
            **Nine
                Months****Increase
                (Decrease)**
            
            ***(In
                millions)***Purchased
                power costs
            
            $
            18
            
            $
            40Other
                operating costs
            
            
            (3)
            
            
            (4)Provision
                for
                depreciation
            
            
            -
            
            
            (1)Amortization
                of regulatory assets
            
            
            (10)
            
            
            (26)General
                Taxes
            
            
            -
            
            
            (1)**Net
                increase in expenses**
            
            **$**
            **5**
            
            **$**
            **8**





I ncreased
      purchased
      power costs in the third quarter and the first nine months of 2006, compared
      with the same periods of 2005, resulted from higher unit prices associated
      with
      a new power supply agreement with FES, partially offset by decreases in KWH
      purchased due to lower generation sales requirements. Other operating costs
      decreased primarily due to lower employee benefit costs *.*




Amortization
      of
      regulatory assets was lower in the third quarter and the first nine months
      of
      2006 as compared to the same periods of 2005 due to the completion of Penn's
      rate restructuring plan at the end of 2005.





*Other
      Income
      (Expense)*





Miscellaneous
      income
      increased $3 million in the third quarter and $10 million in the first
      nine months of 2006, compared with the same periods of 2005, primarily due
      to
      the impact of the generation asset transfer. Excluding the effects of the asset
      transfer, miscellaneous income was substantially unchanged in the third quarter
      and was $3 million higher in the first nine months of 2006, compared with
      the same periods of 2005. The increase in the first nine months of 2006 was
      primarily due to the absence in 2006 of changes for a $0.7 million civil penalty
      payable to the DOJ and a $0.8 million settlement for environmental projects
      in
      connection with the Sammis New Source Review settlement in the first quarter
      of
      2005 (see Outlook Environmental Matters).





*Net
      Interest
      Charges*





Net
      interest charges
      increased $1 million in the third quarter and $4 million in the first nine
      months of 2006 as compared to the same periods of 2005 primarily due to the
      reduction of capitalized interest related to the generation asset transfer.
      Excluding the effect of the asset transfer, interest expense decreased by $1
      million in the third quarter and was substantially unchanged in the first nine
      months of 2006 as compared to the same periods of 2005 due to Penn’s debt
      redemptions.





138











**Capital
      Resources and Liquidity**





Penn’s
      cash
      requirements for the remainder of 2006 for operating expenses, construction
      expenditures and scheduled debt maturities are expected to be met with a
      combination of internal cash and short-term credit arrangements. Available
      borrowing capacity under credit facilities is used to manage working capital
      requirements.





*Changes
      in Cash
      Position*





Penn
      had $36,000 of
      cash and cash equivalents as of September 30, 2006 compared with $24,000 as
      of
      December 31, 2005. The major sources for changes in these balances are
      summarized below.





*Cash
      Flows From
      Operating Activities*





Net
      cash provided
      from operating activities in the first nine months of 2006, compared with the
      corresponding 2005 period, was as follows:





**Nine
                Months Ended****September
                30,****Operating
                Cash Flows**
            
            **2006**
            
            **2005*****(In
                millions)***Cash
                earnings(*)
            
            $
            14
            
            $
            101Working
                capital and other
            
            
            (30)
            
            
            (5)Net
                cash
                provided from operating activities
            
            $
            (16)
            
            $
            96(*)Cash earnings
                are a non-GAAP measure (see reconciliation
                below).





Cash
      earnings (in
      the table above) are not a measure of performance calculated in accordance
      with
      GAAP. Penn believes that cash earnings is a useful financial measure because
      it
      provides investors and management with an additional means of evaluating its
      cash-based operating performance. Generally,
      a
      non-GAAP financial measure is a numerical measure of a company’s historical or
      future financial performance, financial position, or cash flows that either
      excludes or includes amounts, or is subject to adjustment that has the effect
      of
      excluding or including amounts, that are not normally excluded or included
      in
      the most directly comparable measure calculated and presented in accordance
      with
      GAAP. In addition, cash earnings (non-GAAP) are not defined under GAAP.
      Management believes presenting this non-GAAP measure provides useful information
      to investors in assessing Penn’s operating performance from a cash perspective
      without the effects of material unusual economic events. Penn’s management
      frequently references these non-GAAP financial measures in its decision-making,
      using them to facilitate historical and ongoing performance comparisons as
      well
      as comparisons to the performance of peer companies. These non-GAAP measures
      should be considered in addition to, and not as a substitute for, their most
      directly comparable financial measures prepared in accordance with
      GAAP.





**Nine
                  Months Ended****September
                  30,****Reconciliation
                  of Cash Earnings**
              
              
              **2006**
              
              **2005*****(In
                  millions)***Net
                  income
                  (GAAP)
              
              
              $
              7
              
              $
              54Non-cash
                  charges (credits):Provision
                  for
                  depreciation
              
              
              
              7
              
              
              11Amortization
                  of regulatory assets
              
              
              
              3
              
              
              29Nuclear
                  fuel
                  and other amortization
              
              
              
              -
              
              
              13Deferred
                  income taxes and investment tax credits, net
              
              
              
              (3)
              
              
              (8)Other
                  non-cash
                  items
              
              
              
              -
              
              
              2Cash
                  earnings
                  (Non-GAAP)
              
              
              $
              14
              
              $
              101





The
      $87 million
      decrease in cash earnings for the first nine months of 2006, as compared to
      the
      corresponding period of 2005 resulted principally from the generation asset
      transfer, as is described above under “Results of Operations”. The
      $25 million change in working capital was primarily due to increased cash
      outflows from the settlement of accounts payable of $26 million and a
      $20 million change in accrued taxes. These variances were partially offset
      by an increase in cash of $21 million provided from the collection of
      receivables.





139








*Cash
      Flows From
      Financing Activities*





Net
      cash used for
      financing activities totaled $54 million in the first nine months of 2006,
      compared with $25 million in the same period of 2005. The $29 million
      increase resulted from $62 million of long-term debt redemptions in 2006
      principally related to the generation asset transfer discussed above and a
      $15
      million decrease in short-term borrowings, partially offset by a $38 million
      decrease in preferred stock redemptions and an $8 million decrease in common
      stock dividend payments to OE.





As
      of September 30,
      2006, Penn had $2 million of cash and temporary investments (which included
      short-term notes receivable from associated companies) and $21 million of
      short-term indebtedness. Penn has authorization from the FERC to incur
      short-term debt up to its charter limit of $44 million (including the
      utility money pool). Penn had the capability to issue $68 million of
      additional FMB on the basis of property additions and retired bonds as of
      September 30, 2006. Based upon applicable earnings coverage tests, Penn could
      issue up to $136 million of preferred stock (assuming no additional debt
      was issued) as of September 30, 2006.





Penn
      Power Funding
      LLC (Penn Funding), a wholly owned subsidiary of Penn, is a limited liability
      company whose borrowings are secured by customer accounts receivable purchased
      from Penn. Penn Funding can borrow up to $25 million under a receivables
      financing arrangement which expires on June 28, 2007. The financing arrangements
      require payment of an annual facility fee of 0.125% on the entire finance limit.
      As a separate legal entity with separate creditors, Penn Funding would have
      to
      satisfy its separate obligations to creditors before any of its remaining assets
      could be made available to Penn . As
      of September 30,
      2006, the facility was drawn for $19 million.





On
      August 24, 2006,
      Penn, FirstEnergy, OE, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI as
      Borrowers, entered into a new $2.75 billion five-year revolving credit
      facility that expires in August 2011, which replaced the prior $2 billion
      credit facility. FirstEnergy may request an increase in the total commitments
      available under the new facility up to a maximum of $3.25 billion. Borrowings
      under the facility are available to each Borrower separately and will mature
      on
      the earlier of 364 days from the date of borrowing or the August 24, 2011
      commitment expiration date. Penn's borrowing limit under the facility is
      $50 million.





Under
      the revolving
      credit facility, Borrowers may request the issuance of LOCs expiring up to
      one
      year from the date of issuance. The stated amount of outstanding LOCs will
      count
      against total commitments available under the facility and against the
      applicable borrower’s borrowing sub-limit. Total unused borrowing capability
      under the existing credit facility and accounts receivable financing facilities
      totaled $56 million as of September 30, 2006.





The
      revolving credit
      facility contains financial covenants requiring each Borrower to maintain a
      consolidated debt to total capitalization ratio of no more than 65%, measured
      at
      the end of each fiscal quarter. As of September 30, 2006, Penn's debt to total
      capitalization as defined under the revolving credit facility was
      33%.





The
      facility does
      not contain any provisions that either restrict Penn's ability to borrow or
      accelerate repayment of outstanding advances as a result of any change in its
      credit ratings. Pricing is defined in “pricing grids”, whereby the cost of funds
      borrowed under the facility is related to Penn's credit ratings.





Penn
      has the ability
      to borrow from its regulated affiliates and FirstEnergy to meet its short-term
      working capital requirements. FESC administers this money pool and tracks
      surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving
      a loan under the money pool agreements must repay the principal amount, together
      with accrued interest, within 364 days of borrowing the funds. The rate of
      interest is the same for each company receiving a loan from the pool and is
      based on the average cost of funds available through the pool. The average
      interest rate for borrowings under these arrangements in the first nine months
      of 2006 was 5.09%.





Penn's
      access to the
      capital markets and the costs of financing are influenced by the ratings of
      its
      securities and the securities of OE and FirstEnergy. The rating outlook from
      S&P on all securities is stable. Moody's and Fitch's ratings outlook on all
      securities is positive.




In the first nine months of 2006, pollution control notes that were formerly
      obligations of Penn were refinanced and became obligations of FGCO and NGC.
      The
      proceeds from the refinancings were used to repay a portion of their associated
      company notes payable to Penn. With those repayments, Penn redeemed pollution
      control notes in the principal amount of $16.8 million at 5.9%;
      $12.7 million at 6.15%; $14.25 million at 6%; $10.3 million at
      3.61%; and $6.95 million at 5.45%.





140








*Cash
      Flows From
      Investing Activities*





Net
      cash provided
      from investing activities totaled $70 million in the first nine months of
      2006, compared with $71 million of net cash used in the same period of
      2005. The $141 million increase in the 2006 period reflects a $55 million
      reduction in property additions and $78 million from liquidating investments
      (restrictions on short-term investments expired for an escrow fund and a
      mortgage indenture deposit), principally as a result of the generation asset
      transfer discussed above, and a $7 million increase in loan repayments from
      associated companies.





During
      the last
      quarter of 2006, capital requirements for property additions are expected to
      be
      approximately $4 million. Penn has sinking fund requirements of
      approximately $0.5 million for maturing long-term debt during the remainder
      of 2006. These cash requirements are expected to be satisfied from internal
      cash
      and short-term credit arrangements.





Penn’s
      capital
      spending for the period 2006-2010 is expected to be approximately
      $91 million of which approximately $19 million applies to 2006. Penn
      had no other material obligations as of September 30, 2006 that have not been
      recognized on its Consolidated Balance Sheet.





**OUTLOOK**




The electric industry continues to transition to a more competitive environment
      and all of Penn’s customers can select alternative energy suppliers. Penn
      continues to deliver power to residential homes and businesses through its
      existing distribution system, which remains regulated. Customer rates have
      been
      restructured into separate components to support customer choice. Penn has
      a
      continuing responsibility to provide power to those customers not choosing
      to
      receive power from an alternative energy supplier subject to certain
      limits.





***Regulatory
      Matters***





Regulatory
      assets
      and liabilities are costs which have been authorized by the PPUC and the FERC
      for recovery from, or credit to, customers in future periods and, without such
      authorization, would have been charged or credited to income when incurred.
      Penn’s net regulatory liabilities were approximately $64 million as of
      September 30, 2006 and $59 million as of December 31, 2005, and are
      included under Noncurrent Liabilities on the Consolidated Balance Sheets.




Under Pennsylvania's electric competition law, Penn is required to secure
      generation supply for customers who do not choose alternative suppliers for
      their electricity. On October 11, 2005, Penn filed a plan with the PPUC to
      secure electricity supply for its customers at set rates following the end
      of
      its transition period on December 31, 2006. Penn recommended that the RFP
      process cover the period January 1, 2007 through May 31, 2008.
      Hearings before the PPUC were held on January 10, 2006 with main briefs
      filed on January 27, 2006 and reply briefs filed on February 3, 2006.
      On February 16, 2006, the ALJ issued a Recommended Decision to adopt Penn's
      RFP process with modifications. On April 20, 2006, the PPUC approved the
      Recommended Decision with additional modifications to use an RFP process with
      two separate solicitations. An initial solicitation was held for Penn in May
      2006 with all tranches fully subscribed, which was approved by the PPUC on
      June 2, 2006. On July 18, 2006, the second PLR solicitation was held for
      Penn. The tranches for the Residential Group and Small Commercial Group were
      fully subscribed. However, supply was not acquired for two tranches for the
      Large Commercial Group. On July 20, 2006, the PPUC approved the submissions
      for
      the second bid. A contingency solicitation was held on August 15, 2006 for
      the two remaining Large Commercial Group tranches. The PPUC rejected the bids
      from the contingency solicitation and directed Penn’s independent auction
      manager to offer the two unfilled Large Commercial tranches to the companies
      which had won tranches in the prior solicitations. This resulted in the
      acquisition of a supplier for the two remaining tranches, which were filed
      and
      accepted by the PPUC in a secretarial letter that was entered on
      September 22, 2006. On August 24, 2006, Penn made a compliance filing.
      OCA and OSBA filed exceptions to the compliance filing. Penn filed reply
      exceptions on September 5, 2006. On September 21, 2006, Penn submitted
      a revised compliance filing to the PPUC for the Residential Group and Small
      Commercial Group as a result of an agreement between Penn, OCA and OSBA. The
      PPUC approved proposed rates for the large commercial and industrial customers
      at the PPUC Public meeting on October 19, 2006, and found that the results
      of the competitive solicitation process were consistent with prevailing market
      prices.




On May 25, 2006, Penn filed a Petition for Review of the PPUC’s Orders of
      April 28, 2006 and May 4, 2006, which together decided the issues
      associated with Penn’s proposed Interim PLR Supply Plan. Penn has asked the
      Commonwealth Court to review the PPUC’s decision to deny Penn’s recovery of
      certain PLR costs through a reconciliation mechanism and the PPUC’s decision to
      impose a geographic limitation on the sources of alternative energy credits.
      On
      June 7, 2006, the PaDEP filed a Petition for Review appealing the PPUC’s
      ruling on the method by which alternative energy credits may be acquired and
      traded. Penn is unable to predict the outcome of this appeal.





141






On
        December 29,
        2005, the FERC issued an order setting the two power sales agreements for
        hearing. The order criticized the Ohio CBP, and required FES to submit
        additional evidence in support of the reasonableness of the prices charged
        in
        the power sales agreements. A pre-hearing conference was held on January
        18,
        2006 to determine the hearing schedule in this case. Under the procedural
        schedule approved in this case, FES expected an initial decision to be issued
        in
        late January 2007. However, on July 14, 2006, the Chief Judge granted the
        joint
        motion of FES and the Trial Staff to appoint a settlement judge in this
        proceeding and the procedural schedule was suspended pending settlement
        discussions among the parties. A settlement conference was held on September
        5,
        2006. FES and the Ohio Companies, Penn, and the PUCO, along
        with other
        parties, reached an agreement to settle the case. The settlement was filed
        with
        the FERC on October 17, 2006, and was unopposed by the remaining parties,
        including the FERC Trial Staff. Initial comments to the settlement are due
        by
        November 6, 2006.
 
 The
        terms of the
        settlement provide for modification of both the Ohio and Penn power supply
        agreements with FES. The wholesale rate charged by FES under the Penn power
        supply agreement will be no greater than the generation component of charges for
        retail PLR load in Pennsylvania. The FERC is expected to act on this case
        by the
        end of the fourth quarter of 2006.
  As
        a result of Penn’s
        PLR competitive solicitation process approved by the PPUC, FES was selected
        as
        the winning bidder for a number of the tranches for individual customer classes.
        The balance of the tranches will be supplied by unaffiliated power suppliers.
        On
        October 2, 2006, FES filed an application with FERC under Section 205 of
        the
        Federal Power Act for authorization to make these affiliate sales to Penn.
        Interventions or protests were due on this filing on October 23, 2006. Penn
        was
        the only party to file an intervention in this proceeding. The FERC
        is expected
        to act on this filing on or before December 1,
        2006.




See Note 11 to the consolidated financial statements for further details
      and a complete discussion of regulatory matters in Pennsylvania.





***Environmental
      Matters***




Penn accrues environmental liabilities when it concludes that it is probable
      that it has an obligation for such costs and can reasonably estimate the amount
      of such costs. Unasserted claims are reflected in Penn’s determination of
      environmental liabilities and are accrued in the period that they are both
      probable and reasonably estimable.





*W.
      H. Sammis
      Plant*





In
      1999 and 2000,
      the EPA issued NOV or Compliance Orders to nine utilities alleging violations
      of
      the Clean Air Act based on operation and maintenance of 44 power plants,
      including the W. H. Sammis Plant, which was owned at that time by OE and Penn.
      In addition, the DOJ filed eight civil complaints against various investor-owned
      utilities, including a complaint against OE and Penn in the U.S. District Court
      for the Southern District of Ohio. These cases are referred to as New Source
      Review cases.


On March 18, 2005, OE and Penn announced that they had reached a settlement
        with
        the EPA, the DOJ and three states (Connecticut, New Jersey, and New York)
        that
        resolved all issues related to the W. H. Sammis Plant New Source Review
        litigation. This settlement agreement was approved by the Court on July 11,
        2005, and requires reductions of NO X and SO 2 emissions at the W.
        H. Sammis Plant and other coal-fired plants through the installation of
        pollution control devices and provides for stipulated penalties for failure
        to
        install and operate such pollution controls in accordance with that agreement.
        Consequently, if FirstEnergy fails to install such pollution control devices,
        for any reason, including, but not limited to, the failure of any third-party
        contractor to timely meet its delivery obligations for such devices, FirstEnergy
        could be exposed to penalties under the settlement agreement. Capital
        expenditures necessary to meet those requirements are currently estimated
        to be
        $1.5 billion ($400 million of which is expected to be spent in 2007 with
        the
        primary portion of the remaining $1.1 billion expected to be spent in 2008
        and
        2009). On August 26, 2005, FGCO entered into an agreement with Bechtel Power
        Corporation under which Bechtel will engineer, procure, and construct air
        quality control systems for the reduction of SO 2 emissions. FGCO
        also entered into an agreement with B&W on August 25, 2006 to supply flue
        gas desulfurization systems for the reduction of SO 2 emissions.
        Selective Catalytic Reduction (SCR) systems for the reduction of NOx emissions
        also are being installed at the W.H. Sammis Plant under a 1999 agreement
        with
        B&W. The above requirements will be the responsibility of FGCO.
 The settlement agreement also requires OE and Penn to spend up to
          $25 million toward environmentally beneficial projects, which include wind
          energy purchased power agreements over a 20-year term. OE and Penn agreed
          to pay
          a civil penalty of $8.5 million. Results for the first quarter of 2005
          included the penalties paid by OE and Penn of $7.8 million and
          $0.7 million, respectively. OE and Penn also recognized liabilities in the
          first quarter of 2005 of $9.2 million and $0.8 million, respectively,
          for probable future cash contributions toward environmentally beneficial
          projects.





142










***Other
        Legal Proceedings***
 
 There are various lawsuits, claims (including claims for asbestos exposure)
        and
        proceedings related to Penn’s normal business operations pending against Penn.
        The other material items not otherwise discussed above are described
        below.





*Power
      Outages
      and Related Litigation*




On August 14, 2003, various states and parts of southern Canada experienced
      widespread power outages. The outages affected approximately 1.4 million
      customers in FirstEnergy's service area. The U.S. - Canada Power System Outage
      Task Force’s final report in April 2004 on the outages concluded, among other
      things, that the problems leading to the outages began in FirstEnergy’s Ohio
      service area. Specifically,
      the
      final report concluded, among other things, that the initiation of the
      August 14, 2003 power outages resulted from an alleged failure of both
      FirstEnergy and ECAR to assess and understand perceived inadequacies within
      the
      FirstEnergy system; inadequate situational awareness of the developing
      conditions; and a perceived failure to adequately manage tree growth in certain
      transmission rights of way. The Task Force also concluded that there was a
      failure of the interconnected grid's reliability organizations (MISO and PJM)
      to
      provide effective real-time diagnostic support. The final report is publicly
      available through the Department of Energy’s Web site (www.doe.gov). FirstEnergy
      believes that the final report does not provide a complete and comprehensive
      picture of the conditions that contributed to the August 14, 2003 power
      outages and that it does not adequately address the underlying causes of the
      outages. FirstEnergy remains convinced that the outages cannot be explained
      by
      events on any one utility's system. The final report contained 46
“recommendations to prevent or minimize the scope of future blackouts.”
Forty-five of those recommendations related to broad industry or policy matters
      while one, including subparts, related to activities the Task Force recommended
      be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct
      the
      causes of the August 14, 2003 power outages. FirstEnergy implemented
      several initiatives, both prior to and since the August 14, 2003 power
      outages, which were independently verified by NERC as complete in 2004 and
      were
      consistent with these and other recommendations and collectively enhance the
      reliability of its electric system. FirstEnergy’s implementation of these
      recommendations in 2004 included completion of the Task Force recommendations
      that were directed toward FirstEnergy. FirstEnergy is also proceeding with
      the
      implementation of the recommendations that were to be completed subsequent
      to
      2004 and will continue to periodically assess the FERC-ordered Reliability
      Study
      recommendations for forecasted 2009 system conditions, recognizing revised
      load
      forecasts and other changing system conditions which may impact the
      recommendations. Thus far, implementation of the recommendations has not
      required, nor is expected to require, substantial investment in new or material
      upgrades to existing equipment. The FERC or other applicable government agencies
      and reliability coordinators may, however, take a different view as to
      recommended enhancements or may recommend additional enhancements in the future
      as a result of adoption of mandatory reliability standards pursuant to the
      EPACT
      that could require additional material expenditures.




On October 10, 2006, various insurance carriers refiled a complaint in Cuyahoga
      County Common Pleas Court seeking reimbursement for claims paid to numerous
      insureds who allegedly suffered losses as a result of the August 14, 2003
      outages. All of the insureds appear to be non-customers. The plaintiff insurance
      companies are the same claimants in one of the pending PUCO cases. FirstEnergy,
      the Ohio Companies and Penn were served on October 27, 2006, and expect to
      seek summary dismissal of these cases. No estimate of potential liability is
      available for any of these cases.




FirstEnergy is vigorously defending these actions, but cannot predict the
      outcome of any of these proceedings or whether any further regulatory
      proceedings or legal actions may be initiated against the Companies. Although
      unable to predict the impact of these proceedings, if FirstEnergy or its
      subsidiaries were ultimately determined to have legal liability in connection
      with these proceedings, it could have a material adverse effect on FirstEnergy's
      or its subsidiaries' financial condition, results of operations and cash flows.




See Note 10(C) to the consolidated financial statements for further details
      and a complete discussion of other legal proceedings.










143







**New
        Accounting Standards and Interpretations**
 
 *SAB
        108 -
“Considering the Effects of Prior Year Misstatements when Quantifying
        Misstatements in Current Year Financial Statements”*
 
 In September 2006, the SEC issued SAB 108, which provides interpretive guidance
        on how registrants should quantify financial statement misstatements. There
        is
        currently diversity in practice, with the two commonly used methods to quantify
        misstatements being the “rollover” method (which primarily focuses on the income
        statement impact of misstatements) and the “iron curtain” method (which focuses
        on the balance sheet impact). SAB 108 requires registrants to use a dual
        approach whereby both of these methods are considered in evaluating the
        materiality of financial statement errors. Prior materiality assessments
        will
        need to be reconsidered using both the rollover and iron curtain methods.
        This
        guidance will be effective for Penn in the fourth quarter of 2006. Penn does
        not expect this Statement to have a material impact on its financial
        statements.
  *SFAS
        157 - “Fair
        Value Measurements”*





In September 2006, the FASB issued SFAS 157 that establishes how companies
      should measure fair value when they are required to use a fair value measure
      for
      recognition or disclosure purposes under GAAP. This Statement addresses the
      need
      for increased consistency and comparability in fair value measurements and
      for
      expanded disclosures about fair value measurements. The key changes to current
      practice are: (1) the definition of fair value which focuses on an exit price
      rather than entry price; (2) the methods used to measure fair value such as
      emphasis that fair value is a market-based measurement, not an entity-specific
      measurement, as well as the inclusion of an adjustment for risk, restrictions
      and credit standing; and (3) the expanded disclosures about fair value
      measurements.





This Statement is effective for financial statements issued for fiscal years
      beginning after November 15, 2007, and interim periods within those years.
      Penn is currently evaluating the impact of this Statement on its financial
      statements.





*SFAS
                158 -
                “Employers’ Accounting for Defined Benefit Pension and Other
                Postretirement Plans-an amendment of FASB Statements No. 87, 88,
                106, and
                132(R)”*





In September 2006, the FASB issued SFAS 158, which requires companies to
      recognize a net liability or asset to report the overfunded or underfunded
      status of their defined benefit pension and other postretirement benefit plans
      on their balance sheets and recognize changes in funded status in the year
      in
      which the changes occur through other comprehensive income. The funded status
      to
      be measured is the difference between plan assets at fair value and the benefit
      obligation. This Statement requires that gains and losses and prior service
      costs or credits, net of tax, that arise during the period be recognized as
      a
      component of other comprehensive income and not as components of net periodic
      benefit cost. Additional information should also be disclosed in the notes
      to
      the financial statements about certain effects on net periodic benefit cost
      for
      the next fiscal year that arise from delayed recognition of the gains or losses,
      prior service costs or credits, and transition asset or obligation. Upon the
      initial application of this Statement and subsequently, an employer should
      continue to apply the provisions in Statements 87, 88 and 106 in measuring
      plan
      assets and benefit obligations as of the date of its statement of financial
      position and in determining the amount of net periodic benefit cost. This
      Statement is effective for Penn as of December 31, 2006. Penn is currently
      evaluating the impact of this Statement on its financial statements.




*FIN
      48 -
“Accounting for Uncertainty in Income Taxes - an interpretation of FASB
      Statement No. 109.”*


In
 In June 2006, the FASB issued FIN 48 which clarifies the accounting for
        uncertainty in income taxes recognized in an enterprise’s financial statements
        in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” This
        interpretation prescribes a recognition threshold and measurement attribute
        for
        the financial statement recognition and measurement of a tax position taken
        or
        expected to be taken on a tax return. This interpretation also provides guidance
        on derecognition, classification, interest, penalties, accounting in interim
        periods, disclosure and transition. The evaluation of a tax position in
        accordance with this interpretation will be a two-step process. The first
        step
        will determine if it is more likely than not that a tax position will be
        sustained upon examination and should therefore be recognized. The second
        step
        will measure a tax position that meets the more likely than not recognition
        threshold to determine the amount of benefit to recognize in the financial
        statements. This interpretation is effective for fiscal years beginning after
        December 15, 2006. Penn is currently evaluating the impact of this
        Statement.


144





**JERSEY
                  CENTRAL POWER & LIGHT COMPANY****CONSOLIDATED
                  STATEMENTS OF INCOME AND COMPREHENSIVE INCOME****(Unaudited)****Three
                  Months Ended**
              
              **Nine
                  Months Ended****September
                  30,**
              
              **September
                  30,****2006**
              
              **2005**
              
              **2006**
              
              **2005****Restated**
              
              
              
              **Restated****STATEMENTS
                  OF INCOME**
              ***(In
                  thousands)*****REVENUES**
              
              
              $
              911,068
              
              $
              900,247
              
              $
              2,098,344
              
              $
              2,024,630**EXPENSES**Purchased
                  power
              
              
              
              546,125
              
              
              517,213
              
              
              1,204,880
              
              
              1,115,738Other
                  operating costs
              
              
              
              90,578
              
              
              112,690
              
              
              245,711
              
              
              293,996Provision
                  for
                  depreciation
              
              
              
              21,099
              
              
              19,659
              
              
              62,553
              
              
              59,721Amortization
                  of regulatory assets
              
              
              
              78,052
              
              
              85,485
              
              
              210,323
              
              
              224,109Deferral
                  of
                  new regulatory assets
              
              
              
              -
              
              
              (1,097
              )
              
              -
              
              
              (28,862
              )General
                  taxes
              
              
              
              19,187
              
              
              19,538
              
              
              49,691
              
              
              49,802Total
                  expenses
              
              
              
              755,041
              
              
              753,488
              
              
              1,773,158
              
              
              1,714,504**OPERATING
                  INCOME**
              
              
              
              156,027
              
              
              146,759
              
              
              325,186
              
              
              310,126**OTHER
                  INCOME (EXPENSE):**Miscellaneous
                  income
              
              
              
              2,091
              
              
              4,777
              
              
              8,162
              
              
              5,264Interest
                  expense
              
              
              
              (21,437
              )
              
              (19,960
              )
              
              (62,420
              )
              
              (60,963
              )Capitalized
                  interest
              
              
              
              1,004
              
              
              497
              
              
              2,933
              
              
              1,337Total
                  other
                  expense
              
              
              
              (18,342
              )
              
              (14,686
              )
              
              (51,325
              )
              
              (54,362
              )**INCOME
                  BEFORE INCOME TAXES**
              
              
              
              137,685
              
              
              132,073
              
              
              273,861
              
              
              255,764**INCOME
                  TAXES**
              
              
              
              58,316
              
              
              58,197
              
              
              120,506
              
              
              114,136**NET
                  INCOME**
              
              
              
              79,369
              
              
              73,876
              
              
              153,355
              
              
              141,628**PREFERRED
                  STOCK DIVIDEND REQUIREMENTS**
              
              
              
              917
              
              
              125
              
              
              1,167
              
              
              375**EARNINGS
                  ON COMMON STOCK**
              
              
              $
              78,452
              
              $
              73,751
              
              $
              152,188
              
              $
              141,253**STATEMENTS
                  OF COMPREHENSIVE INCOME****NET
                  INCOME**
              
              
              $
              79,369
              
              $
              73,876
              
              $
              153,355
              
              $
              141,628**OTHER
                  COMPREHENSIVE INCOME:**Unrealized
                  gain on derivative hedges
              
              
              
              100
              
              
              103
              
              
              207
              
              
              208Income
                  tax
                  expense related to other comprehensive income
              
              
              
              41
              
              
              42
              
              
              84
              
              
              85Other
                  comprehensive income, net of tax
              
              
              
              59
              
              
              61
              
              
              123
              
              
              123**TOTAL
                  COMPREHENSIVE INCOME**
              
              
              $
              79,428
              
              $
              73,937
              
              $
              153,478
              
              $
              141,751The
                  preceding
                  Notes to Consolidated Financial Statements as they relate to Jersey
                  Central Power & Light Company are an integral part of these
                  statements.
   145
  **JERSEY
                    CENTRAL POWER & LIGHT COMPANY****CONSOLIDATED
                    BALANCE SHEETS****(Unaudited)****September
                    30,**
                
                **December
                    31,****2006**
                
                **2005*****(In
                    thousands)*****ASSETS****CURRENT
                    ASSETS:**Cash
                    and cash
                    equivalents
                
                
                
                $
                58
                
                $
                102Receivables-Customers
                    (less accumulated provisions of $4,066,000 and $3,830,000,respectively,
                    for uncollectible accounts)
                
                
                
                
                310,347
                
                
                258,077Associated
                    companies
                
                
                
                
                161
                
                
                203Other
                    (less
                    accumulated provisions of $216,000 and $204,000,respectively,
                    for uncollectible accounts)
                
                
                
                
                39,565
                
                
                41,456Notes
                    receivable - associated companies
                
                
                
                
                27,056
                
                
                18,419Materials
                    and
                    supplies, at average cost
                
                
                
                
                2,017
                
                
                2,104Prepaid
                    taxes
                
                
                
                
                40,060
                
                
                10,137Other
                
                
                
                
                9,045
                
                
                6,928428,309
                
                
                337,426**UTILITY
                    PLANT:**In
                    service
                
                
                
                
                4,008,742
                
                
                3,902,684Less
                    -
                    Accumulated provision for depreciation
                
                
                
                
                1,467,604
                
                
                1,445,7182,541,138
                
                
                2,456,966Construction
                    work in progress
                
                
                
                
                77,450
                
                
                98,7202,618,588
                
                
                2,555,686**OTHER
                    PROPERTY AND INVESTMENTS:**Nuclear
                    fuel
                    disposal trust
                
                
                
                
                168,375
                
                
                164,203Nuclear
                    plant
                    decommissioning trusts
                
                
                
                
                156,205
                
                
                145,975Other
                
                
                
                
                2,080
                
                
                2,580326,660
                
                
                312,758**DEFERRED
                    CHARGES AND OTHER ASSETS:**Regulatory
                    assets
                
                
                
                
                2,178,460
                
                
                2,226,591Goodwill
                
                
                
                
                1,977,551
                
                
                1,985,858Prepaid
                    pension costs
                
                
                
                
                152,113
                
                
                148,054Other
                
                
                
                
                17,587
                
                
                17,7334,325,711
                
                
                4,378,236$
                7,699,268
                
                $
                7,584,106**LIABILITIES
                    AND CAPITALIZATION****CURRENT
                    LIABILITIES:**Currently
                    payable long-term debt
                
                
                
                $
                70,140
                
                $
                207,231Notes
                    payable-Associated
                    companies
                
                
                
                
                137,184
                
                
                181,346Accounts
                    payable-Associated
                    companies
                
                
                
                
                9,754
                
                
                37,955Other
                
                
                
                
                169,570
                
                
                149,501Accrued
                    taxes
                
                
                
                
                37,365
                
                
                54,356Accrued
                    interest
                
                
                
                
                36,212
                
                
                19,916Cash
                    collateral from suppliers
                
                
                
                
                48,582
                
                
                141,225Other
                
                
                
                
                65,148
                
                
                86,884573,955
                
                
                878,414**CAPITALIZATION:**Common
                    stockholder's equity-Common
                    stock,
                    $10 par value, authorized 16,000,000 shares-15,371,270
                    shares outstanding
                
                
                
                
                153,713
                
                
                153,713Other
                    paid-in
                    capital
                
                
                
                
                2,995,029
                
                
                3,003,190Accumulated
                    other comprehensive loss
                
                
                
                
                (1,907
                )
                
                (2,030
                )Retained
                    earnings
                
                
                
                
                163,079
                
                
                55,890Total
                    common
                    stockholder's equity
                
                
                
                
                3,309,914
                
                
                3,210,763Preferred
                    stock
                
                
                
                
                -
                
                
                12,649Long-term
                    debt
                    and other long-term obligations
                
                
                
                
                1,327,809
                
                
                972,0614,637,723
                
                
                4,195,473**NONCURRENT
                    LIABILITIES:**Power
                    purchase
                    contract loss liability
                
                
                
                
                1,205,064
                
                
                1,237,249Accumulated
                    deferred income taxes
                
                
                
                
                814,236
                
                
                812,034Nuclear
                    fuel
                    disposal costs
                
                
                
                
                181,317
                
                
                175,156Asset
                    retirement obligations
                
                
                
                
                83,188
                
                
                79,527Retirement
                    benefits
                
                
                
                
                71,785
                
                
                72,454Other
                
                
                
                
                132,000
                
                
                133,7992,487,590
                
                
                2,510,219**COMMITMENTS
                  AND CONTINGENCIES (Note 10)**$
                7,699,268
                
                $
                7,584,106The
                    preceding
                    Notes to Consolidated Financial Statements as they relate to
                    Jersey
                    Central Power & Light Company are an integral part of these balance
                    sheets.
  
 146
  **JERSEY
                    CENTRAL POWER & LIGHT COMPANY****CONSOLIDATED
                    STATEMENTS OF CASH FLOWS****(Unaudited)****Nine
                    Months Ended****September
                    30,****2006**
                
                **2005****Restated*****(In
                    thousands)*****CASH
                    FLOWS FROM OPERATING ACTIVITIES:**Net
                    income
                
                $
                153,355
                
                $
                141,628Adjustments
                    to
                    reconcile net income to net cash from operating activities
                    -Provision
                    for
                    depreciation
                
                
                62,553
                
                
                59,721Amortization
                    of regulatory assets
                
                
                210,323
                
                
                224,109Deferral
                    of
                    new regulatory assets
                
                
                -
                
                
                (28,862
                )Deferred
                    purchased power and other costs
                
                
                (213,621
                )
                
                (168,646
                )Deferred
                    income taxes and investment tax credits, net
                
                
                25,217
                
                
                5,204Accrued
                    compensation and retirement benefits
                
                
                (4,196
                )
                
                (6,545
                )Cash
                    collateral from (returned to) suppliers
                
                
                (108,926
                )
                
                76,674Decrease
                    (increase) in operating assets -Receivables
                
                
                (50,337
                )
                
                (25,626
                )Materials
                    and
                    supplies
                
                
                86
                
                
                572Prepaid
                    taxes
                
                
                (29,923
                )
                
                1,264Other
                    current
                    assets
                
                
                (2,118
                )
                
                (3,028
                )Increase
                    (decrease) in operating liabilities -Accounts
                    payable
                
                
                (8,131
                )
                
                26,214Accrued
                    taxes
                
                
                (16,992
                )
                
                77,341Accrued
                    interest
                
                
                16,296
                
                
                14,931Other
                
                
                (15,130
                )
                
                25,814Net
                    cash
                    provided from operating activities
                
                
                18,456
                
                
                420,765**CASH
                    FLOWS FROM FINANCING ACTIVITIES:**New
                    Financing-Long-term
                    debt
                
                
                382,400
                
                
                -Redemptions
                    and Repayments-Long-term
                    debt
                
                
                (162,157
                )
                
                (67,648
                )Short-term
                    borrowings, net
                
                
                (44,162
                )
                
                (133,600
                )Preferred
                    stock
                
                
                (13,461
                )
                
                -Dividend
                    Payments-Common
                    stock
                
                
                (45,000
                )
                
                (83,000
                )Preferred
                    stock
                
                
                (354
                )
                
                (375
                )Net
                    cash
                    provided from (used for) financing activities
                
                
                117,266
                
                
                (284,623
                )**CASH
                    FLOWS FROM INVESTING ACTIVITIES:**Property
                    additions
                
                
                (123,540
                )
                
                (133,498
                )Loan
                    repayments from (loans to) associated companies, net
                
                
                (8,638
                )
                
                685Proceeds
                    from
                    nuclear decommissioning trust fund sales
                
                
                138,936
                
                
                103,360Investments
                    in
                    nuclear decommissioning trust funds
                
                
                (141,107
                )
                
                (105,531
                )Other
                
                
                (1,417
                )
                
                (749
                )Net
                    cash used
                    for investing activities
                
                
                (135,766
                )
                
                (135,733
                )Net
                    increase
                    (decrease) in cash and cash equivalents
                
                
                (44
                )
                
                409Cash
                    and cash
                    equivalents at beginning of period
                
                
                102
                
                
                162Cash
                    and cash
                    equivalents at end of period
                
                $
                58
                
                $
                571The
                    preceding
                    Notes to Consolidated Financial Statements as they relate to
                    Jersey
                    Central Power & Light Company are an integral part of these
                    statements.
   147













***Report
      of Independent Registered Public Accounting Firm***





























To
      the Stockholder
      and Board of


Directors
      of Jersey
      Central Power & Light Company:





We
      have reviewed the
      accompanying consolidated balance sheet of Jersey Central Power & Light
      Company and its subsidiaries as of September 30, 2006, and the related
      consolidated statements of income and comprehensive income for each of the
      three-month and nine-month periods ended September 30, 2006 and 2005 and the
      consolidated statements of cash flows for the nine-month periods ended September
      30, 2006 and 2005. These interim financial statements are the responsibility
      of
      the Company’s management.





We
      conducted our
      review in accordance with the standards of the Public Company Accounting
      Oversight Board (United States). A review of interim financial information
      consists principally of applying analytical procedures and making inquiries
      of
      persons responsible for financial and accounting matters. It is substantially
      less in scope than an audit conducted in accordance with the standards of the
      Public Company Accounting Oversight Board, the objective of which is the
      expression of an opinion regarding the financial statements taken as a whole.
      Accordingly, we do not express such an opinion.





Based
      on our review,
      we are not aware of any material modifications that should be made to the
      accompanying consolidated interim financial statements for them to be in
      conformity with accounting principles generally accepted in the United States
      of
      America.





We
      have previously
      audited, in accordance with the standards of the Public Company Accounting
      Oversight Board (United States), the consolidated balance sheet as of December
      31, 2005, and the related consolidated statements of income, capitalization,
      common stockholder’s equity, preferred stock, cash flows and taxes for the year
      then ended (not presented herein), and in our report [which contained references
      to the Company’s restatement of its previously issued consolidated financial
      statements for the years ended December 31, 2004 and 2003 as discussed in Note
      2(I) to those consolidated financial statements] dated February 27, 2006, we
      expressed an unqualified opinion on those consolidated financial statements.
      In
      our opinion, the information set forth in the accompanying consolidated balance
      sheet as of December 31, 2005, is fairly stated in all material respects in
      relation to the consolidated balance sheet from which it has been
      derived.





PricewaterhouseCoopers
                LLP
              Cleveland,
                Ohio
              October
                31,
                2006














148





**JERSEY
      CENTRAL POWER & LIGHT COMPANY**





**MANAGEMENT’S
      DISCUSSION AND** **ANALYSIS
      OF**


**RESULTS
      OF
      OPERATIONS** **** **AND
      FINANCIAL CONDITION**








JCP&L
      is a
      wholly owned, electric utility subsidiary of FirstEnergy. JCP&L conducts
      business in New Jersey, providing regulated electric transmission and
      distribution services. JCP&L also provides generation services to those
      customers electing to retain JCP&L as their power supplier.





**Restatements**




As
      further discussed in Note 15 to the Consolidated Financial Statements, JCP&L
      restated its consolidated financial statements for the three months and nine
      months ended September 30, 2005. The revisions are the result of a tax
      audit from the State of New Jersey, in which JCP&L became aware that the New
      Jersey Transitional Energy Facilities Assessment is not an allowable deduction
      for state income tax purposes .





**Results
      of Operations**





Earnings
      on common
      stock in the third quarter of 2006 increased to $78 million from
      $74 million in 2005. The increase was principally due to higher revenues,
      decreased other operating costs and lower amortization of regulatory assets,
      partially offset by increased purchased power costs. In the first nine months
      of
      2006, earnings on common stock increased to $152 million compared to
      $141 million for the same period in 2005. The increase was primarily due to
      higher revenues, lower other operating costs and reduced amortization of
      regulatory assets, partially offset by increased purchased power costs and
      the
      absence of the new regulatory asset recognized in 2005.





*Revenues*





Revenues
      increased
      $11 million or 1.2% in the third quarter of 2006 and $74 million or
      3.6% for the first nine months of 2006 compared with the same periods of 2005.
      The higher revenues in both periods were primarily due to retail generation
      revenue increases ($49 million and $115 million in the third quarter and the
      first nine months of 2006, respectively), partially offset by decreases in
      wholesale revenue ($22 million in the third quarter and $28 million in the
      first nine months of 2006). Distribution revenues declined $20 million in
      the third quarter and $15 million in the first nine months of 2006 compared
      to the same periods of the prior year.





The
      retail
      generation revenue increases in both the third quarter and the first nine months
      of 2006, as compared to the previous year, were due to higher unit prices
      resulting from the BGS auction effective in May 2006, which offset declines
      in
      retail generation KWH sales. Revenue from residential customers increased
      $20 million and $48 million in the third quarter and the first nine
      months of 2006, respectively, as compared to the same periods in 2005.
      Generation revenue from commercial customers also increased for the same periods
      by $26 million and $63 million, respectively. The milder weather in
      the third quarter (cooling degree days were 18.6% below the previous year)
      and
      in the first nine months of 2006 (heating degree days were 17.7% below and
      cooling degree days were 15.3% below the previous year) resulted in lower KWH
      sales to residential customers in the third quarter and the first nine months
      of
      2006. KWH sales to commercial customers increased 0.4% in the third quarter
      and
      2.1% for the first nine months of 2006 as an increase in the number of
      commercial customers more than offset the impact of milder weather. Revenues
      from industrial customers increased $2 million in the third quarter of 2006
      as a result of higher unit prices and KWH sales. The industrial sector revenue
      increase of $4 million in the first nine months of 2006 also reflected higher
      unit prices but were partially offset by lower sales compared to the prior
      year
      period. Wholesale sales revenues decreased $22 million in the third quarter
      and $28 million for the first nine months of 2006 as compared to 2005 due
      to lower unit prices.





The
      decrease in
      distribution revenues in the third quarter of 2006 resulted from lower KWH
      throughput and the impact of the new securitization (see “Regulatory Matters”
further below) which reduced distribution revenues and increased other revenues.
      Distribution KWH deliveries declined for the first nine months of 2006 as
      compared to the previous year which decreased revenues by $15 million. The
      distribution revenue reduction was primarily due to lower KWH throughput
      partially offset by higher prices resulting from a distribution rate increase
      pursuant to the stipulated settlements approved by the NJBPU on May 25, 2005.
      Other revenues increased $4 million and $2 million in the third
      quarter and in the first nine months of 2006, respectively, as compared to
      the
      comparable periods in 2005 due to the new transition bond charge
      revenue.





149








Changes
      in KWH sales
      by customer class in the third quarter and the first nine months of 2006
      compared to the same periods of 2005 are summarized in the following
      table:





**Three**
            
            **Nine****Changes
                in KWH Sales**
            
            **Months**
            
            **Months****Increase
                (Decrease)**Electric
                Generation:Retail
            
            
            (3.6
            )%
            
            (2.3
            )%Wholesale
            
            
            (0.4
            )%
            
            0.6
            %**Total
                Electric Generation Sales**
            
            
            **(3.0**
            **)%**
            
            **(1.7**
            **)%**Distribution
                Deliveries:Residential
            
            
            (6.6
            )%
            
            (5.5
            )%Commercial
            
            
            1.4
            %
            
            0.1
            %Industrial
            
            
            (8.8
            )%
            
            (7.5
            )%**Total
                Distribution Deliveries**
            
            
            **(3.7**
            **)%**
            
            **(3.5**
            **)%**




*Expenses*





Total
      operating
      expenses increased by $2 million in the third quarter and $59 million in the
      first nine months of 2006 as compared to the same periods of the prior year.
      The
      following table presents changes from the prior year by expense
      category:





**Three**
            
            **Nine****Expenses
                - Changes**
            
            **Months**
            
            **Months*****(In
                millions)*****Increase
                (Decrease)**Purchased
                power costs
            
            $
            29
            
            $
            89Other
                operating costs
            
            
            (22
            )
            
            (48
            )Provision
                for
                depreciation
            
            
            1
            
            
            3Amortization
                of regulatory assets
            
            
            (7
            )
            
            (14
            )Deferral
                of
                new regulatory assets
            
            
            1
            
            
            29**Net
                increase in expenses**
            
            $
            2
            
            $
            59





The
      increases in
      purchased power costs reflected higher unit prices resulting from the 2006
      BGS
      auction. Other operating costs in the third quarter of 2005
      included the
      affect of an arbitration decision in connection with a JCP&L bargaining
      union grievance challenging JCP&L's call out procedure. As a result of the
      arbitration decision, JCP&L reserved $16 million in the third quarter of
      2005. Other operating costs were also higher in both periods of 2005 due to
      an
      extensive effort to improve system reliability as well as impacts from a labor
      union strike that ended on March 15, 2005. Amortization of regulatory assets
      decreased $7 million in the third quarter and $14 million in the first
      nine months of 2006 compared to the same periods in 2005 due to a reduction
      in
      the level of MTC revenue recovery. The changes in the deferral of new regulatory
      assets reflect the NJBPU’s 2005 approval for JCP&L to defer accelerated tree
      trimming and other reliability costs that were incurred in 2003 and
      2004.





Miscellaneous
      income
      decreased $3 million in the third quarter of 2006, but increased $3 million
      for
      the first nine months compared to the same periods in 2005. The decrease in
      the
      third quarter of 2006 was due to the absence in 2006 of a gain from the sale
      of
      property in 2005, while the increase for the first nine months of 2006 was
      attributable to income received from customer requested service projects.




**Capital
      Resources and Liquidity**





JCP&L’s
      cash
      requirements for the remainder of 2006 for expenses, construction expenditures
      and scheduled debt maturities are expected to be met with cash from operations.





*Changes
      in Cash
      Position*





As
      of
      September 30, 2006, JCP&L had $58,000 of cash and cash equivalents
      compared with $102,000 as of December 31, 2005. The major sources for
      changes in these balances are summarized below.





150








*Cash
      Flows From
      Operating Activities*





Cash
      provided from
      operating activities in the first nine months of 2006 and 2005 were as follows:





**Nine
                Months Ended****September
                30,****Operating
                Cash Flows**
            
            **2006**
            
            **2005*****(In
                millions)***Cash
                earnings(1)
            
            $
            234
            
            $
            227Working
                capital and other
            
            
            (216
            )
            
            194Net
                cash
                provided from operating activities
            
            $
            18
            
            $
            421(1)Cash earnings
                are a non-GAAP measure (see reconciliation below).





Cash
      earnings (in
      the table above) are not a measure of performance calculated in accordance
      with
      GAAP. JCP&L believes that cash earnings is a useful financial measure
      because it provides investors and management with an additional means of
      evaluating its cash-based operating performance. Generally, a non-GAAP financial
      measure is a numerical measure of a company’s historical or future financial
      performance, financial position, or cash flows that either excludes or includes
      amounts, or is subject to adjustment that has the effect of excluding or
      including amounts, that are not normally excluded or included in the most
      directly comparable measure calculated and presented in accordance with GAAP.
      In
      addition, cash earnings (non-GAAP) are not defined under GAAP. Management
      believes presenting this non-GAAP measure provides useful information to
      investors in assessing JCP&L’s operating performance from a cash perspective
      without the effects of material unusual economic events. JCP&L’s management
      frequently references these non-GAAP financial measures in its decision-making,
      using them to facilitate historical and ongoing performance comparisons as
      well
      as comparisons to the performance of peer companies. These non-GAAP measures
      should be considered in addition to, and not as a substitute for, their most
      directly comparable financial measures prepared in accordance with
      GAAP.





**Nine
                Months Ended****September
                30,****Reconciliation
                of Cash Earnings******
            
            **2006**
            
            **2005*****(In
                millions)***Net
                income
                (GAAP)
            
            $
            153
            
            $
            142Non-cash
                charges (credits):Provision
                for
                depreciation
            
            
            63
            
            
            60Amortization
                of regulatory assets
            
            
            210
            
            
            224Deferral
                of
                new regulatory assets
            
            
            -
            
            
            (29
            )Deferred
                purchased power and other costs
            
            
            (214
            )
            
            (169
            )Deferred
                income taxes
            
            
            26
            
            
            6Other
                non-cash
                items
            
            
            (4
            )
            
            (7
            )Cash
                earnings
                (Non-GAAP)
            
            $
            234
            
            $
            227





The
      $7 million
      increase in cash earnings is described under “Results of Operations.” The
      $410 million change in working capital primarily resulted from a
      $186 million change in cash collateral returned to suppliers, changes in
      accrued taxes of $94 million, payables of $34 million, prepaid taxes of $30
      million, receivables of $25 million, and the 2005 arbitration decision of
      $16 million. In the year 2005, JCP&L received cash collateral payments from
      its suppliers of $135 million. During the first nine months of 2006, JCP&L
      returned $109 million back to its suppliers.





*Cash
      Flows From
      Financing Activities*





Net
      cash provided
      from financing activities was $117 million in the first nine months of 2006
      as
      compared to net cash used of $285 million in same period of 2005. The
      change resulted from a $382 million issuance of long-term debt, a $90 million
      decrease in short-term debt redemptions and a $38 million reduction in
      common stock dividend payments to FirstEnergy, partially offset by
      $108 million of additional debt and preferred stock redemptions in the
      first nine months of 2006.





151








JCP&L  had
      $27 million
      of cash and temporary investments (which includes short-term notes receivable
      from associated companies) and approximately $137 million of short-term
      indebtedness as of September 30, 2006. JCP&L has authorization from the
      FERC to incur short-term debt up to its charter limit of $429 million
      (including the utility money pool). JCP&L will not issue FMB other than as
      collateral for senior notes, since its senior note indenture prohibits (subject
      to certain exceptions) JCP&L from issuing any debt which is senior to the
      senior notes. As of September 30, 2006, JCP&L had the capability to
      issue $626 million of additional senior notes based upon FMB collateral. As
      of September 30, 2006, based upon applicable earnings coverage tests and
      its charter, JCP&L could issue $1.3 billion of preferred stock
      (assuming no additional debt was issued).





JCP&L
      has the
      ability to borrow from FirstEnergy and its regulated affiliates to meet its
      short-term working capital requirements. FESC administers this money pool and
      tracks surplus funds of FirstEnergy and its regulated subsidiaries. Companies
      receiving a loan under the money pool agreement must repay the principal,
      together with accrued interest, within 364 days of borrowing the funds. The
      rate
      of interest is the same for each company receiving a loan from the pool and
      is
      based on the average cost of funds available through the pool. The average
      interest rate for borrowings in the first nine months of 2006 was 5.09%.





On
      August 24, 2006,
      JCP&L, FirstEnergy, OE, Penn, CEI, TE, Penelec, Met-Ed, FES and ATSI, as
      Borrowers, entered into a new $2.75 billion five-year revolving credit facility,
      which replaced the prior $2 billion credit facility. FirstEnergy may
      request an increase in the total commitments available under the new facility
      up
      to a maximum of $3.25 billion. Commitments
      under
      the new facility are available until August 24, 2011, unless the lenders
      agree, at the request of the Borrowers, to two additional one-year extensions.
      Generally, borrowings under the facility must be repaid within 364 days.
      Available amounts for each Borrower are subject to a specified sub-limit, as
      well as applicable regulatory and other limitations. JCP&L's
      borrowing limit under the facility is $425 million.





Under
      the revolving
      credit facility, borrowers may request the issuance of letters of credit
      expiring up to one year from the date of issuance. The stated amount of
      outstanding letters of credit will count against total commitments available
      under the facility and against the applicable borrower’s borrowing sub-limit.





The
      revolving credit
      facility contains financial covenants requiring each borrower to maintain a
      consolidated debt to total capitalization ratio of no more than 65%. As of
      September 30, 2006, JCP&L's debt to total capitalization as defined
      under the revolving credit facility was 23%.





The
      facility does
      not contain any provisions that either restrict JCP&L's ability to borrow or
      accelerate repayment of outstanding advances as a result of any change in its
      credit ratings. Pricing is defined in “pricing grids”, whereby the cost of funds
      borrowed under the facility is related to its credit ratings.





JCP&L's
      access
      to the capital markets and the costs of financing are dependent on the ratings
      of its securities and that of FirstEnergy. As of September 30, 2006,
      JCP&L's and FirstEnergy’s ratings outlook from S&P on all securities was
      stable. The ratings outlook from Moody’s and Fitch on all securities is
      positive.




On June 8, 2006, the NJBPU approved JCP&L’s request to issue
      securitization bonds associated with BGS stranded cost deferrals. On
      August 10, 2006, JCP&L Transition Funding II, a wholly owned subsidiary
      of JCP&L, issued $182 million of transition bonds with a weighted
      average interest rate of 5.5%. As required by the Electric Discount and Energy
      Competition Act of 1999, as amended, JCP&L used the proceeds principally to
      reduce stranded costs, including basic generation transition costs, through
      the
      retirement of debt, including short-term debt, or equity or both, and also
      to
      pay related expenses.





On
      May 12,
      2006, JCP&L issued $200 million of 6.40% secured Senior Notes due 2036.
      The proceeds of the offering were used to repay at maturity $150 million
      aggregate principal amount of JCP&L’s 6.45% Senior Notes due May 15,
      2006 and for general corporate purposes.





*Cash
      Flows From
      Investing Activities*





Net
      cash used for
      investing activities was $136 million in the first nine months of 2006,
      unchanged from the previous year. The $10 million reduction in property
      additions was completely offset by $10 million of loans to associated
      companies.





During
      the last quarter
      of 2006, capital requirements for property additions and improvements are
      expected to be about $36 million. These cash requirements are expected to
      be satisfied from cash from operations.





JCP&L’s
      capital
      spending for the period 2006-2010 is expected to be approximately
      $909 million for property additions, of which approximately
      $159 million applies to 2006.





152








**Market
      Risk Information**





JCP&L
      uses
      various market risk sensitive instruments, including derivative contracts,
      primarily to manage the risk of price fluctuations. FirstEnergy’s Risk Policy
      Committee, comprised of members of senior management, provides general oversight
      to risk management activities.





*Commodity
      Price
      Risk*




JCP&L is exposed to market risk primarily due to fluctuations in
      electricity, energy transmission and natural gas prices. To manage the
      volatility relating to these exposures, JCP&L uses a variety of
      non-derivative and derivative instruments, including forward contracts, options,
      futures contracts and swaps. The derivatives are used principally for hedging
      purposes. Derivatives that fall within the scope of SFAS 133 must be
      recorded at their fair value and marked to market. The majority of JCP&L’s
      derivative hedging contracts qualify for the normal purchase and normal sale
      exception under SFAS 133 and are therefore excluded from the table below.
      Contracts that are not exempt from such treatment include the power purchase
      agreements with NUG entities that were structured pursuant to the Public Utility
      Regulatory Policies Act of 1978. These non-trading contracts had been adjusted
      to fair value at the end of each quarter, with a corresponding regulatory asset
      recognized for above-market costs. The changes in the fair value of commodity
      derivative contracts related to energy production during the third quarter
      and
      first nine months of 2006 are summarized in the following table:





**Three
                Months Ended**
            
            **Nine
                Months Ended****Increase
                (Decrease) in the Fair Value**
            **September
                30, 2006**
            
            **September
                30, 2006****of
                Commodity Derivative Contracts**
            **Non-Hedge**
            
            **Hedge**
            
            **Total**
            
            **Non-Hedge**
            
            **Hedge**
            
            **Total*****(In
                millions)*****Change
                in the Fair Value of****Commodity
                Derivative Contracts:**Outstanding
                net liability at beginning of period
            $
            (1,111
            )
            $
            -
            
            $
            (1,111
            )
            $
            (1,223
            )
            $
            -
            
            $
            (1,223
            )Additions/change
                in value of existing contracts
            
            (164
            )
            
            -
            
            
            (164
            )
            
            (193
            )
            
            -
            
            
            (193
            )Settled
                contracts
            
            81
            
            
            -
            
            
            81
            
            
            222
            
            
            -
            
            
            222**Net
                Liabilities - Derivative Contracts**
              **at
                End
                of Period****(1)**
            $
            (1,194
            )
            $
            -
            
            $
            (1,194
            )
            $
            (1,194
            )
            $
            -
            
            $
            (1,194
            )**Impact
                of Changes in Commodity Derivative Contracts****(2)**Income
                Statement effects (pre-tax)
            $
            (2
            )
            $
            -
            
            $
            (2
            )
            $
            (1
            )
            $
            -
            
            $
            (1
            )Balance
                Sheet
                effects:
            
            
            
            
            -Regulatory
                assets (net)
            $
            81
            
            $
            -
            
            $
            81
            
            $
            (30
            )
            $
            -
            
            $
            (30
            )





(1)  These
      represent NUG
      contracts that are offset by a regulatory asset.


(2)  Represents
      the
      change in value of existing contracts, settled contracts and changes in
      techniques/assumptions.




Derivatives are included on the Consolidated Balance Sheet as of
      September 30, 2006 as follows:





**Balance
                Sheet Classification**
            
            **Non-Hedge**
            
            **Hedge**
            
            **Total*****(In
                millions)*****Non-Current-**Other
                deferred
                charges
            
            $
            11
            
            $
            -
            
            $
            11Other
                noncurrent liabilities
            
            
            (1,205
            )
            
            -
            
            
            (1,205
            )**Net
                liabilities**
            
            **$**
            **(1,194**
            **)**
            **$**
            **-**
            
            **$**
            **(1,194**
            **)**








153








The
      valuation of
      derivative contracts is based on observable market information to the extent
      that such information is available. In cases where such information is not
      available, JCP&L relies on model-based information. The model provides
      estimates of future regional prices for electricity and an estimate of related
      price volatility. JCP&L uses these results to develop estimates of fair
      value for financial reporting purposes and for internal management decision
      making. Sources of information for the valuation of commodity derivative
      contracts as of September 30, 2006 are summarized by year in the following
      table:





**Source
                of Information****Fair
                Value by Contract Year**
            
            **2006**(1)
            
            **2007**
            
            **2008**
            
            **2009**
            
            **2010**
            
            **Thereafter**
            
            **Total*****(In
                millions)***Other
                external
                sources(2)
            
            $
            (66
            )
            $
            (269
            )
            $
            (248
            )
            $
            (197
            )
            $
            -
            
            $
            -
            
            $
            (780
            )Prices
                based
                on models
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            (181
            )
            
            (233
            )
            
            (414
            )**Total**(3)
            
            **$**
            **(66**
            **)**
            **$**
            **(269**
            **)**
            **$**
            **(248**
            **)**
            **$**
            **(197**
            **)**
            **$**
            **(181**
            **)**
            **$**
            **(233**
            **)**
            **$**
            **(1,194**
            **)**





(1)  For
      the last quarter
      of 2006.


(2)  Broker
      quote
      sheets.


(3)  These
      represent NUG
      contracts that are offset by a regulatory asset .





JCP&L performs sensitivity analyses to estimate its exposure to the market
      risk of its commodity positions. A hypothetical 10% adverse shift in quoted
      market prices in the near term on both its trading and non-trading derivative
      instruments would not have had a material effect on JCP&L’s consolidated
      financial position or cash flows as of September 30, 2006. JCP&L estimates
      that if energy commodity prices experienced an adverse 10% change, net income
      for the next twelve months would not change, as the prices for all commodity
      positions are already above the contract price caps.





*Equity
      Price
      Risk*





Included
      in nuclear
      decommissioning trusts are marketable equity securities carried at their current
      fair value of approximately $91 million and $84 million as of
      September 30, 2006 and December 31, 2005, respectively. A hypothetical
      10% decrease in prices quoted by stock exchanges would result in a
      $9 million reduction in fair value as of September 30, 2006.





**Regulatory
      Matters**




Regulatory assets are costs which have been authorized by the NJBPU and the
      FERC
      for recovery from customers in future periods or for which authorization is
      probable. Without the probability of such authorization, costs currently
      recorded as regulatory assets would have been charged to income as incurred.
      All
      of JCP&L’s regulatory assets are expected to continue to be recovered under
      the provisions of the regulatory proceedings discussed below. JCP&L’s
      regulatory assets totaled $2.2 billion as of September 30, 2006 and
      December 31, 2005.




JCP&L is permitted to defer for future collection from customers the amounts
      by which its costs of supplying BGS to non-shopping customers and costs incurred
      under NUG agreements exceed amounts collected through BGS and NUGC rates and
      market sales of NUG energy and capacity. As of September 30, 2006, the
      accumulated deferred cost balance totaled approximately $340 million. New
      Jersey law allows for securitization of JCP&L's deferred balance upon
      application by JCP&L and a determination by the NJBPU that the conditions of
      the New Jersey restructuring legislation are met. On February 14, 2003,
      JCP&L filed for approval to securitize the July 31, 2003 deferred balance.
      On June 8, 2006, the NJBPU approved JCP&L’s request to issue securitization
      bonds associated with BGS stranded cost deferrals. On August 10, 2006,
      JCP&L Transition Funding II, a wholly owned subsidiary of JCP&L, issued
      $182 million of transition bonds with a weighted average interest rate of 5.5%.




On
      December 2, 2005, JCP&L filed its request for recovery of
      $165 million of actual above-market NUG costs incurred from August 1,
      2003 through October 31, 2005 and forecasted above-market NUG costs for
      November and December 2005. On February 23, 2006, JCP&L filed updated data
      reflecting actual amounts through December 31, 2005 of $154 million of
      costs incurred since July 31, 2003. On March 29, 2006, a pre-hearing
      conference was held with the presiding ALJ. On July 18, 2006, JCP&L
      filed rebuttal testimony that included a request for an additional
      $14 million of costs that had been eliminated from the securitized amount.
      Evidentiary hearings were held during September 2006 and the briefing schedule
      has been postponed pending settlement discussions.





154







An NJBPU Decision and Order approving a Phase II Stipulation of Settlement
      and
      resolving the Motion for Reconsideration of the Phase I Order was issued on
      May
      31, 2005. The Phase II Settlement includes a performance standard pilot program
      with potential penalties of up to 0.25% of allowable equity return. The Order
      requires that JCP&L file quarterly reliability reports (CAIDI and SAIFI
      information related to the performance pilot program) through December 2006
      and
      updates to reliability related project expenditures until all projects are
      completed. The latest quarterly reliability reports were submitted on
      September 12, 2006. As of September 30, 2006, there were no
      performance penalties issued by the NJBPU.




Reacting to the higher closing prices of the 2006 BGS fixed rate auction, the
      NJBPU, on March 16, 2006, initiated a generic proceeding to evaluate the
      auction process and potential options for the future. On April 6, 2006,
      initial comments were submitted. A public meeting was held on April 21, 2006
      and
      a legislative-type hearing was held on April 28, 2006. On June 21, 2006,
      the NJBPU approved the continued use of a descending block auction for the
      Fixed
      Price Residential Class. JCP&L filed its 2007 BGS company specific addendum
      on July 10, 2006. On October 27, 2006, the NJBPU approved the auction
      format to procure the 2007 Commercial Industrial Energy Price as well as the
      specific rules for both the Fixed Price and Commercial Industrial Energy Price
      auctions. These rules were essentially unchanged from the prior
      auctions.




In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony
      on June 7, 2004 supporting a continuation of the current level and duration
      of the funding of TMI-2 decommissioning costs by New Jersey customers without
      a
      reduction, termination or capping of the funding. On September 30, 2004,
      JCP&L filed an updated TMI-2 decommissioning study. This study resulted in
      an updated total decommissioning cost estimate of $729 million (in 2003
      dollars) compared to the estimated $528 million (in 2003 dollars) from the
      prior
      1995 decommissioning study. The DRA filed comments on February 28, 2005
      requesting that decommissioning funding be suspended. On March 18, 2005,
      JCP&L filed a response to the Ratepayer Advocate’s comments. A schedule for
      further NJBPU proceedings has not yet been set.





On
        August 1,
        2005, the NJBPU established a proceeding to determine whether additional
        ratepayer protections are required at the state level in light of the repeal
        of
        PUHCA pursuant to the EPACT. An NJBPU proposed rulemaking to address the
        issues
        was published in the NJ Register on December 19, 2005. The proposal would
        prevent a holding company that owns a gas or electric public utility from
        investing more than 25% of the combined assets of its utility and
        utility-related subsidiaries into businesses unrelated to the utility industry.
        A public hearing was held on February 7, 2006 and comments were submitted
        to the NJBPU. On August 16, 2006, the NJBPU approved the regulations with
        an effective date of October 2, 2006. These regulations are not expected
        to
        materially impact FirstEnergy or JCP&L. Also, in the same proceeding, the
        NJBPU Staff issued an additional draft proposal on March 31, 2006 addressing
        various issues including access to books and records, ring-fencing, cross
        subsidization, corporate governance and related matters. With the approval
        of
        the NJBPU Staff, the affected utilities jointly submitted an alternative
        proposal on June 1, 2006. Comments on the alternative proposal were submitted
        on
        June 15, 2006.




On December 21, 2005, the NJBPU initiated a generic proceeding and requested
      comments in order to formulate an appropriate regulatory treatment for
      investment tax credits related to generation assets divested by New Jersey’s
      four electric utility companies. Comments were filed by the utilities and by
      the
      DRA. JCP&L filed a request with the IRS for a ruling on the issue. JCP&L
      was advised by the IRS on April 10, 2006 that the ruling was tentatively
      adverse. On April 28, 2006, the NJBPU directed JCP&L to withdraw its
      request for a private letter ruling on this issue, which had been previously
      filed with the IRS as ordered by the NJBPU. On May 11, 2006, after a JCP&L
      Motion for Reconsideration was denied by the NJBPU, JCP&L filed to withdraw
      the request for a private letter ruling. On July 19, 2006, the IRS acknowledged
      that the JCP&L ruling request was withdrawn.





On
      November 18,
      2004, the FERC issued an order eliminating the RTOR for transmission service
      between the MISO and PJM regions. The FERC also ordered the MISO, PJM and the
      transmission owners within MISO and PJM to submit compliance filings containing
      a SECA mechanism to recover lost RTOR revenues during a 16-month transition
      period from load serving entities. The FERC issued orders in 2005 setting the
      SECA for hearing. ATSI, JCP&L, Met-Ed, Penelec, and FES continue to be
      involved in the FERC hearings concerning the calculation and imposition of
      the
      SECA charges. The hearing was held in May 2006. Initial briefs were submitted
      on
      June 9, 2006, and reply briefs were filed on June 27, 2006. The Presiding Judge
      issued an Initial Decision on August 10, 2006, rejecting the compliance filings
      made by the RTOs and transmission owners, ruling on various issues and directing
      new compliance filings. This decision is subject to review and approval by
      the
      FERC. Briefs addressing the Initial Decision were filed on September 11, 2006
      and October 20, 2006. A final order could be issued by the FERC by the end
      of
      2006.





155








On
      January 31, 2005,
      certain PJM transmission owners made three filings with the FERC pursuant to
      a
      settlement agreement previously approved by the FERC. JCP&L, Met-Ed and
      Penelec were parties to that proceeding and joined in two of the filings. In
      the
      first filing, the settling transmission owners submitted a filing justifying
      continuation of their existing rate design within the PJM RTO. In the second
      filing, the settling transmission owners proposed a revised Schedule 12 to
      the
      PJM tariff designed to harmonize the rate treatment of new and existing
      transmission facilities. Interventions and protests were filed on February
      22,
      2005. In the third filing, Baltimore Gas and Electric Company and Pepco
      Holdings, Inc. requested a formula rate for transmission service provided within
      their respective zones. On May 31, 2005, the FERC issued an order on these
      cases. First, it set for hearing the existing rate design and indicated that
      it
      will issue a final order within six months. American Electric Power Company,
      Inc. filed in opposition proposing to create a "postage stamp" rate for high
      voltage transmission facilities across PJM. Second, the FERC approved the
      proposed Schedule 12 rate harmonization. Third, the FERC accepted the proposed
      formula rate, subject to refund and hearing procedures. On June 30, 2005, the
      settling PJM transmission owners filed a request for rehearing of the May 31,
      2005 order. On March 20, 2006, a settlement was filed with FERC in the formula
      rate proceeding that generally accepts the companies' formula rate proposal.
      The
      FERC issued an order approving this settlement on April 19, 2006. Hearings
      in
      the PJM rate design case concluded in April 2006. On July 13, 2006, an Initial
      Decision was issued by the ALJ. The ALJ adopted the Trial Staff’s position that
      the cost of all PJM transmission facilities should be recovered through a
      postage stamp rate. ****** The
      ALJ recommended
      an April 1, 2006 effective date for this change in rate design. If the FERC
      accepts this recommendation, the transmission rate applicable to many load
      zones
      in PJM would increase. FirstEnergy believes that significant additional
      transmission revenues would have to be recovered from the JCP&L, Met-Ed and
      Penelec transmission zones within PJM. JCP&L, Met-Ed and Penelec as part of
      the Responsible Pricing Alliance, filed a brief addressing the Initial Decision
      on August 14, 2006 and September 5, 2006. The case will be reviewed by the
      FERC
      with a decision anticipated in the fourth quarter of 2006. ******




See Note 11 to the consolidated financial statements for further details
      and a complete discussion of regulatory matters in New Jersey.





**Environmental
      Matters**




JCP&L accrues environmental liabilities when it concludes that it is
      probable that it has an obligation for such costs and can reasonably determine
      the amount of such costs. Unasserted claims are reflected in JCP&L’s
      determination of environmental liabilities and are accrued in the period that
      they are both probable and reasonably estimable.




JCP&L has been named as a PRP at waste disposal sites which may require
      cleanup under the Comprehensive Environmental Responsive, Comprehension and
      Liability Act of 1980. Allegations of disposal of hazardous substances at
      historical sites and the liability involved are often unsubstantiated and
      subject to dispute; however, federal law provides that PRPs for a particular
      site are held liable on a joint and several basis. Therefore, environmental
      liabilities that are considered probable have been recognized on the
      Consolidated Balance Sheet as of September 30, 2006, based on estimates of
      the total costs of cleanup, JCP&L’s proportionate responsibility for such
      costs and the financial ability of other unaffiliated entities to pay. In
      addition, JCP&L has accrued liabilities for environmental remediation of
      former manufactured gas plants in New Jersey; those costs are being recovered
      by
      JCP&L through a non-bypassable SBC. Total liabilities of approximately
      $55 million have been accrued through September 30, 2006.





See
      Note 10(B)
      to the consolidated financial statements for further details and a complete
      discussion of environmental matters.





**Other
      Legal Proceedings**




There are various lawsuits, claims (including claims for asbestos exposure)
      and
      proceedings related to JCP&L's normal business operations pending against
      JCP&L. The other material items not otherwise discussed below are described
      in Note 10(C) to the consolidated financial statements.





156




On August 14, 2003, various states and parts of southern Canada experienced
      widespread power outages. The outages affected approximately 1.4 million
      customers in FirstEnergy's service area. The U.S. - Canada Power System Outage
      Task Force’s final report in April 2004 on the outages concluded, among other
      things, that the problems leading to the outages began in FirstEnergy’s Ohio
      service area. Specifically,
      the
      final report concluded, among other things, that the initiation of the
      August 14, 2003 power outages resulted from an alleged failure of both
      FirstEnergy and ECAR to assess and understand perceived inadequacies within
      the
      FirstEnergy system; inadequate situational awareness of the developing
      conditions; and a perceived failure to adequately manage tree growth in certain
      transmission rights of way. The Task Force also concluded that there was a
      failure of the interconnected grid's reliability organizations (MISO and PJM)
      to
      provide effective real-time diagnostic support. The final report is publicly
      available through the Department of Energy’s Web site (www.doe.gov). FirstEnergy
      believes that the final report does not provide a complete and comprehensive
      picture of the conditions that contributed to the August 14, 2003 power
      outages and that it does not adequately address the underlying causes of the
      outages. FirstEnergy remains convinced that the outages cannot be explained
      by
      events on any one utility's system. The final report contained 46
“recommendations to prevent or minimize the scope of future blackouts.”
Forty-five of those recommendations related to broad industry or policy matters
      while one, including subparts, related to activities the Task Force recommended
      be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct
      the
      causes of the August 14, 2003 power outages. FirstEnergy implemented
      several initiatives, both prior to and since the August 14, 2003 power
      outages, which were independently verified by NERC as complete in 2004 and
      were
      consistent with these and other recommendations and collectively enhance the
      reliability of its electric system. FirstEnergy’s implementation of these
      recommendations in 2004 included completion of the Task Force recommendations
      that were directed toward FirstEnergy. FirstEnergy is also proceeding with
      the
      implementation of the recommendations that were to be completed subsequent
      to
      2004 and will continue to periodically assess the FERC-ordered Reliability
      Study
      recommendations for forecasted 2009 system conditions, recognizing revised
      load
      forecasts and other changing system conditions which may impact the
      recommendations. Thus far, implementation of the recommendations has not
      required, nor is expected to require, substantial investment in new or material
      upgrades to existing equipment. The FERC or other applicable government agencies
      and reliability coordinators may, however, take a different view as to
      recommended enhancements or may recommend additional enhancements in the future
      as a result of adoption of mandatory reliability standards pursuant to the
      EPACT
      that could require additional material expenditures.




FirstEnergy was also named, along with several other entities, in a complaint
      in
      New Jersey State Court. The allegations against FirstEnergy were based, in
      part,
      on an alleged failure to protect the citizens of Jersey City from an electrical
      power outage. None of FirstEnergy’s subsidiaries serve customers in Jersey City.
      A responsive pleading has been filed. On April 28, 2006, the Court granted
      FirstEnergy's motion to dismiss. The plaintiff has not appealed.




FirstEnergy is vigorously defending these actions, but cannot predict the
      outcome of any of these proceedings or whether any further regulatory
      proceedings or legal actions may be initiated against the Companies. Although
      unable to predict the impact of these proceedings, if FirstEnergy or its
      subsidiaries were ultimately determined to have legal liability in connection
      with these proceedings, it could have a material adverse effect on FirstEnergy's
      or its subsidiaries' financial condition, results of operations and cash flows.




JCP&L's bargaining unit employees filed a grievance challenging JCP&L's
      2002 call-out procedure that required bargaining unit employees to respond
      to
      emergency power outages. On May 20, 2004, an arbitration panel concluded
      that the call-out procedure violated the parties' collective bargaining
      agreement. At the conclusion of the June 1, 2005 hearing, the arbitration
      panel decided not to hear testimony on damages and closed the proceedings.
      On
      September 9, 2005, the arbitration panel issued an opinion to award
      approximately $16 million to the bargaining unit employees. On February 6,
      2006, a federal district court granted a union motion to dismiss as premature
      a
      JCP&L appeal of the award filed on October 18, 2005. JCP&L intends
      to re-file an appeal again in federal district court once the damages associated
      with this case are identified at an individual employee level. JCP&L
      recognized a liability for the potential $16 million award in
      2005.




The other material items not otherwise discussed above are described in
      Note 10(C) to the consolidated financial statements.





157








**New
      Accounting Standards and Interpretations**





*SAB
      108 -
“Considering the Effects of Prior Year Misstatements when Quantifying
      Misstatements in Current Year Financial Statements”*





In September 2006, the SEC issued SAB 108, which provides interpretive guidance
      on how registrants should quantify financial statement misstatements. There
      is
      currently diversity in practice, with the two commonly used methods to quantify
      misstatements being the “rollover” method (which primarily focuses on the income
      statement impact of misstatements) and the “iron curtain” method (which focuses
      on the balance sheet impact). SAB 108 requires registrants to use a dual
      approach whereby both of these methods are considered in evaluating the
      materiality of financial statement errors. Prior materiality assessments will
      need to be reconsidered using both the rollover and iron curtain methods. This
      guidance will be effective for JCP&L in the fourth quarter of 2006.
      JCP&L does
      not expect this
      Statement to have a material impact on its financial statements.





*SFAS
      157 - “Fair
      Value Measurements”*





In September 2006, the FASB issued SFAS 157, that establishes how companies
      should measure fair value when they are required to use a fair value measure
      for
      recognition or disclosure purposes under GAAP. This Statement addresses the
      need
      for increased consistency and comparability in fair value measurements and
      for
      expanded disclosures about fair value measurements. The key changes to current
      practice are: (1) the definition of fair value which focuses on an exit price
      rather than entry price; (2) the methods used to measure fair value such as
      emphasis that fair value is a market-based measurement, not an entity-specific
      measurement, as well as the inclusion of an adjustment for risk, restrictions
      and credit standing; and (3) the expanded disclosures about fair value
      measurements.





This Statement is effective for financial statements issued for fiscal years
      beginning after November 15, 2007, and interim periods within those years.
      JCP&L is currently evaluating the impact of this Statement on its financial
      statements.





*SFAS
                158 -
                “Employers’ Accounting for Defined Benefit Pension and Other
                Postretirement Plans-an amendment of FASB Statements No. 87, 88,
                106, and
                132(R)”*





In September 2006, the FASB issued SFAS 158, which requires companies to
      recognize a net liability or asset to report the overfunded or underfunded
      status of their defined benefit pension and other postretirement benefit plans
      on their balance sheets and recognize changes in funded status in the year
      in
      which the changes occur through other comprehensive income. The funded status
      to
      be measured is the difference between plan assets at fair value and the benefit
      obligation. This Statement requires that gains and losses and prior service
      costs or credits, net of tax, that arise during the period be recognized as
      a
      component of other comprehensive income and not as components of net periodic
      benefit cost. Additional information should also be disclosed in the notes
      to
      the financial statements about certain effects on net periodic benefit cost
      for
      the next fiscal year that arise from delayed recognition of the gains or losses,
      prior service costs or credits, and transition asset or obligation. Upon the
      initial application of this Statement and subsequently, an employer should
      continue to apply the provisions in Statements 87, 88 and 106 in measuring
      plan
      assets and benefit obligations as of the date of its statement of financial
      position and in determining the amount of net periodic benefit cost. This
      Statement is effective for JCP&L as of December 31, 2006. JCP&L is
      currently evaluating the impact of this Statement on its financial
      statements.





*FSP
                FIN
                46(R)-6 - “Determining the Variability to Be Considered in Applying FASB
                interpretation No. 46(R)”*





In
      April 2006, the
      FASB issued FSP FIN 46(R)-6 that addresses how a reporting enterprise should
      determine the variability to be considered in applying FASB interpretation
      No.
      46 (revised December 2003). JCP&L adopted FIN 46(R) in the first quarter of
      2004, consolidating VIE’s when JCP&L or one of its subsidiaries is
      determined to be the VIE’s primary beneficiary. The variability that is
      considered in applying interpretation 46(R) affects the determination of (a)
      whether the entity is a VIE; (b) which interests are variable interests in
      the
      entity; and (c) which party, if any, is the primary beneficiary of the VIE.
      This
      FSP states that the variability to be considered shall be based on an analysis
      of the design of the entity, involving two steps:





Step
                1:
            Analyze
                the
                nature of the risks in the entityStep
                2:
            Determine
                the
                purpose(s) for which the entity was created and determine the variability
                the entity is designed to create and pass along to its interest
                holders.








158








After
      determining
      the variability to consider, the reporting enterprise can determine which
      interests are designed to absorb that variability. The guidance in this FSP
      is
      applied prospectively to all entities (including newly created entities) with
      which that enterprise first becomes involved and to all entities previously
      required to be analyzed under interpretation 46(R) when a reconsideration event
      has occurred after July 1, 2006. JCP&L does not expect this Statement
      to have a material impact on its financial statements.





*FIN
      48 -
“Accounting for Uncertainty in Income Taxes - an interpretation of FASB
      Statement No. 109.”*





In
      June 2006, the
      FASB issued FIN 48 which clarifies the accounting for uncertainty in income
      taxes recognized in an enterprise’s financial statements in accordance with FASB
      Statement No. 109, “Accounting for Income Taxes.” This interpretation prescribes
      a recognition threshold and measurement attribute for the financial statement
      recognition and measurement of a tax position taken or expected to be taken
      on a
      tax return. This interpretation also provides guidance on derecognition,
      classification, interest, penalties, accounting in interim periods, disclosure
      and transition. The evaluation of a tax position in accordance with this
      interpretation will be a two-step process. The first step will determine if
      it
      is more likely than not that a tax position will be sustained upon examination
      and should therefore be recognized. The second step will measure a tax position
      that meets the more likely than not recognition threshold to determine the
      amount of benefit to recognize in the financial statements. This interpretation
      is effective for fiscal years beginning after December 15, 2006. JCP&L is
      currently evaluating the impact of this Statement.





159





**METROPOLITAN
                    EDISON
                    COMPANY****CONSOLIDATED
                    STATEMENTS OF INCOME AND COMPREHENSIVE
                    INCOME****(Unaudited)****Three
                    Months Ended**
                
                **Nine
                    Months Ended****September
                    30,**
                
                **September
                    30,****2006**
                
                **2005**
                
                **2006**
                
                **2005*****(In
                    thousands)*****REVENUES**
                
                $
                356,181
                
                $
                333,180
                
                $
                949,613
                
                $
                892,097**EXPENSES:**Purchased
                    power
                
                
                184,508
                
                
                186,148
                
                
                487,465
                
                
                467,911Other
                    operating costs
                
                
                108,740
                
                
                81,774
                
                
                229,394
                
                
                192,892Provision
                    for
                    depreciation
                
                
                10,197
                
                
                9,323
                
                
                31,390
                
                
                32,221Amortization
                    of regulatory assets
                
                
                33,560
                
                
                32,853
                
                
                89,277
                
                
                86,760Deferral
                    of
                    new regulatory assets
                
                
                (44,213
                )
                
                -
                
                
                (89,794
                )
                
                -General
                    taxes
                
                
                21,362
                
                
                19,906
                
                
                60,578
                
                
                56,201Total
                    expenses
                
                
                314,154
                
                
                330,004
                
                
                808,310
                
                
                835,985**OPERATING
                    INCOME**
                
                
                42,027
                
                
                3,176
                
                
                141,303
                
                
                56,112**OTHER
                    INCOME (EXPENSE):**Interest
                    income
                
                
                8,053
                
                
                9,109
                
                
                25,767
                
                
                27,578Miscellaneous
                    income
                
                
                1,477
                
                
                2,296
                
                
                5,881
                
                
                6,725Interest
                    expense
                
                
                (12,291
                )
                
                (10,891
                )
                
                (35,546
                )
                
                (33,512
                )Capitalized
                    interest
                
                
                355
                
                
                150
                
                
                966
                
                
                401Total
                    other
                    income (expense)
                
                
                (2,406
                )
                
                664
                
                
                (2,932
                )
                
                1,192**INCOME
                    BEFORE INCOME TAXES**
                
                
                39,621
                
                
                3,840
                
                
                138,371
                
                
                57,304**INCOME
                    TAXES**
                
                
                14,631
                
                
                2,835
                
                
                55,390
                
                
                24,160**NET
                    INCOME**
                
                
                24,990
                
                
                1,005
                
                
                82,981
                
                
                33,144**OTHER
                    COMPREHENSIVE INCOME:**Unrealized
                    gain on derivative hedges
                
                
                83
                
                
                84
                
                
                251
                
                
                252Unrealized
                    gain on available for sale securities
                
                
                -
                
                
                67
                
                
                -
                
                
                67Other
                    comprehensive income
                
                
                83
                
                
                151
                
                
                251
                
                
                319Income
                    tax
                    expense related to other comprehensive income
                
                
                34
                
                
                62
                
                
                104
                
                
                132Other
                    comprehensive income, net of tax
                
                
                49
                
                
                89
                
                
                147
                
                
                187**TOTAL
                    COMPREHENSIVE INCOME**
                
                $
                25,039
                
                $
                1,094
                
                $
                83,128
                
                $
                33,331The
                    preceding
                    Notes to Consolidated Financial Statements as they relate to
                    Metropolitan
                    Edison Company are an integral part of these
                    statements.
   160
  **METROPOLITAN
                    EDISON COMPANY****CONSOLIDATED
                    BALANCE SHEETS****(Unaudited)****September
                    30,**
                
                **December
                    31,****2006**
                
                **2005*****(In
                    thousands)*****ASSETS****CURRENT
                    ASSETS:**Cash
                    and cash
                    equivalents
                
                
                $
                133
                
                $
                120Receivables-Customers
                    (less accumulated provisions of $4,301,000 and $4,352,000,respectively,
                    for uncollectible accounts)
                
                
                
                130,777
                
                
                129,854Associated
                    companies
                
                
                
                6,179
                
                
                37,267Other
                
                
                
                11,265
                
                
                8,780Notes
                    receivable from associated companies
                
                
                
                32,720
                
                
                27,867Prepayments
                    and other
                
                
                
                16,159
                
                
                7,912197,233
                
                
                211,800**UTILITY
                    PLANT:**In
                    service
                
                
                
                1,901,091
                
                
                1,856,425Less
                    -
                    Accumulated provision for depreciation
                
                
                
                730,720
                
                
                721,5661,170,371
                
                
                1,134,859Construction
                    work in progress
                
                
                
                19,669
                
                
                20,4371,190,040
                
                
                1,155,296**OTHER
                    PROPERTY AND INVESTMENTS:**Nuclear
                    plant
                    decommissioning trusts
                
                
                
                256,198
                
                
                234,854Other
                
                
                
                1,363
                
                
                1,453257,561
                
                
                236,307**DEFERRED
                    CHARGES AND OTHER ASSETS:**Goodwill
                
                
                
                860,227
                
                
                864,438Regulatory
                    assets
                
                
                
                364,889
                
                
                309,556Prepaid
                    pension costs
                
                
                
                94,205
                
                
                89,005Other
                
                
                
                66,417
                
                
                51,2851,385,738
                
                
                1,314,284$
                3,030,572
                
                $
                2,917,687**LIABILITIES
                    AND CAPITALIZATION****CURRENT
                    LIABILITIES:**Currently
                    payable long-term debt
                
                
                $
                50,000
                
                $
                100,000Short-term
                    borrowings-Associated
                    companies
                
                
                
                181,871
                
                
                140,240Other
                
                
                
                75,000
                
                
                -Accounts
                    payable-Associated
                    companies
                
                
                
                14,004
                
                
                37,220Other
                
                
                
                49,170
                
                
                27,507Accrued
                    taxes
                
                
                
                7,460
                
                
                17,911Accrued
                    interest
                
                
                
                9,130
                
                
                9,438Other
                
                
                
                22,905
                
                
                24,274409,540
                
                
                356,590**CAPITALIZATION:**Common
                    stockholder's equity-Common
                    stock,
                    without par value, authorized 900,000 shares-859,000
                    shares
                    outstanding
                
                
                
                1,282,846
                
                
                1,287,093Accumulated
                    other comprehensive loss
                
                
                
                (1,422
                )
                
                (1,569
                )Retained
                    earnings
                
                
                
                108,556
                
                
                30,575Total
                    common
                    stockholder's equity
                
                
                
                1,389,980
                
                
                1,316,099Long-term
                    debt
                    and other long-term obligations
                
                
                
                541,979
                
                
                591,8881,931,959
                
                
                1,907,987**NONCURRENT
                    LIABILITIES:**Accumulated
                    deferred income taxes
                
                
                
                375,544
                
                
                344,929Accumulated
                    deferred investment tax credits
                
                
                
                9,444
                
                
                10,043Nuclear
                    fuel
                    disposal costs
                
                
                
                40,958
                
                
                39,567Asset
                    retirement obligations
                
                
                
                148,782
                
                
                142,020Retirement
                    benefits
                
                
                
                56,674
                
                
                57,809Other
                
                
                
                57,671
                
                
                58,742689,073
                
                
                653,110**COMMITMENTS
                  AND CONTINGENCIES (Note 10)**$
                3,030,572
                
                $
                2,917,687The
                    preceding
                    Notes to Consolidated Financial Statements as they relate to
                    Metropolitan
                    Edison Company are an integral part of these balance
                    sheets.
   161
  **METROPOLITAN
                    EDISON COMPANY****CONSOLIDATED
                    STATEMENTS OF CASH FLOWS****(Unaudited)****Nine
                    Months Ended****September
                    30,****2006**
                
                **2005*****(In
                    thousands)*****CASH
                    FLOWS FROM OPERATING ACTIVITIES:**Net
                    income
                
                
                $
                82,981
                
                $
                33,144Adjustments
                    to
                    reconcile net income to net cash from operating activities
                    -Provision
                    for
                    depreciation
                
                
                
                31,390
                
                
                32,221Amortization
                    of regulatory assets
                
                
                
                89,277
                
                
                86,760Deferred
                    costs
                    recoverable as regulatory assets
                
                
                
                (53,406
                )
                
                (48,156
                )Deferral
                    of
                    new regulatory assets
                
                
                
                (89,794
                )
                
                -Deferred
                    income taxes and investment tax credits, net
                
                
                
                27,895
                
                
                (10,336
                )Accrued
                    compensation and retirement benefits
                
                
                
                (6,007
                )
                
                (4,506
                )Cash
                    collateral to suppliers
                
                
                
                (21,500
                )
                
                -Decrease
                    (increase) in operating assets -Receivables
                
                
                
                27,680
                
                
                113,298Prepayments
                    and other current assets
                
                
                
                (8,247
                )
                
                (2,228
                )Increase
                    (decrease) in operating liabilities -Accounts
                    payable
                
                
                
                (1,553
                )
                
                (44,505
                )Accrued
                    taxes
                
                
                
                (10,451
                )
                
                (9,710
                )Accrued
                    interest
                
                
                
                (308
                )
                
                (2,156
                )Other
                
                
                
                (1,777
                )
                
                2,602Net
                    cash
                    provided from operating activities
                
                
                
                66,180
                
                
                146,428**CASH
                    FLOWS FROM FINANCING ACTIVITIES:**New
                    Financing-Short-term
                    borrowings, net
                
                
                
                116,624
                
                
                -Redemptions
                    and Repayments-Long-term
                    debt
                
                
                
                (100,000
                )
                
                (37,830
                )Short-term
                    borrowings, net
                
                
                
                -
                
                
                (3,335
                )Dividend
                    Payments-Common
                    stock
                
                
                
                (5,000
                )
                
                (44,000
                )Net
                    cash
                    provided from (used for) financing activities
                
                
                
                11,624
                
                
                (85,165
                )**CASH
                    FLOWS FROM INVESTING ACTIVITIES:**Property
                    additions
                
                
                
                (65,332
                )
                
                (56,075
                )Proceeds
                    from
                    nuclear decommissioning trust fund sales
                
                
                
                151,593
                
                
                119,207Investments
                    in
                    nuclear decommissioning trust funds
                
                
                
                (158,705
                )
                
                (126,319
                )Loan
                    repayments from (loans to) associated companies, net
                
                
                
                (4,853
                )
                
                2,267Other
                
                
                
                (494
                )
                
                (343
                )Net
                    cash used
                    for investing activities
                
                
                
                (77,791
                )
                
                (61,263
                )Net
                    change in
                    cash and cash equivalents
                
                
                
                13
                
                
                -Cash
                    and cash
                    equivalents at beginning of period
                
                
                
                120
                
                
                120Cash
                    and cash
                    equivalents at end of period
                
                
                $
                133
                
                $
                120The
                    preceding
                    Notes to Consolidated Financial Statements as they relate to
                    Metropolitan
                    Edison Company are an integral part of these
                    statements.
   162





















***Report
      of Independent Registered Public Accounting Firm***





























To
      the Stockholder
      and Board of


Directors
      of
      Metropolitan Edison Company:





We
      have reviewed the
      accompanying consolidated balance sheet of Metropolitan Edison Company and
      its
      subsidiaries as of September 30, 2006, and the related consolidated statements
      of income and comprehensive income for each of the three-month and nine-month
      periods ended September 30, 2006 and 2005 and the consolidated statements of
      cash flows for the nine-month periods ended September 30, 2006 and 2005. These
      interim financial statements are the responsibility of the Company’s
      management.





We
      conducted our
      review in accordance with the standards of the Public Company Accounting
      Oversight Board (United States). A review of interim financial information
      consists principally of applying analytical procedures and making inquiries
      of
      persons responsible for financial and accounting matters. It is substantially
      less in scope than an audit conducted in accordance with the standards of the
      Public Company Accounting Oversight Board, the objective of which is the
      expression of an opinion regarding the financial statements taken as a whole.
      Accordingly, we do not express such an opinion.





Based
      on our review,
      we are not aware of any material modifications that should be made to the
      accompanying consolidated interim financial statements for them to be in
      conformity with accounting principles generally accepted in the United States
      of
      America.





We
      have previously
      audited, in accordance with the standards of the Public Company Accounting
      Oversight Board (United States), the consolidated balance sheet as of December
      31, 2005, and the related consolidated statements of income, capitalization,
      common stockholder’s equity, preferred stock, cash flows and taxes for the year
      then ended (not presented herein), and in our report [which contained references
      to the Company’s change in its method of accounting for asset retirement
      obligations as of January 1, 2003 and conditional asset retirement obligations
      as of December 31, 2005 as discussed in Note 2(G) and Note 9 to those
      consolidated financial statements] dated February 27, 2006, we expressed an
      unqualified opinion on those consolidated financial statements. In our opinion,
      the information set forth in the accompanying consolidated balance sheet as
      of
      December 31, 2005, is fairly stated in all material respects in relation to
      the
      consolidated balance sheet from which it has been derived.





PricewaterhouseCoopers
                LLP
              Cleveland,
                Ohio
              October
                31,
                2006








163





**METROPOLITAN
      EDISON COMPANY**





**MANAGEMENT’S
      DISCUSSION AND ANALYSIS OF**


**RESULTS
      OF
      OPERATIONS AND FINANCIAL CONDITION**











Met-Ed
      is a wholly
      owned, electric utility subsidiary of FirstEnergy. Met-Ed conducts business
      in
      eastern Pennsylvania, providing regulated electric transmission and distribution
      services. Met-Ed also provides generation service to those customers electing
      to
      retain Met-Ed as their power supplier.





**Results
      of Operations**





Net
      income in the
      third quarter of 2006 increased to $25 million from $1 million in the third
      quarter of 2005. This increase reflects the deferral of new regulatory assets
      and higher revenues, partially offset by higher other operating costs as
      discussed below. For the first nine months of 2006, net income increased to
      $83
      million from $33 million in the same period of 2005. This increase reflects
      the
      deferral of new regulatory assets and higher revenues, partially offset by
      higher purchased power costs, amortization of regulatory assets, general taxes
      and other operating costs as discussed below.





*Revenues*





Revenues
      increased
      by $23 million, or 6.9%, in the third quarter of 2006 and $58 million, or 6.4%,
      in the first nine months of 2006, compared with the same periods of 2005.
      Increases in both periods were primarily due to higher retail generation
      electric revenues ($12 million for the third quarter and $39 million for the
      first nine months of 2006), which reflected higher composite prices in all
      customer classes. For the third quarter of 2006, higher KWH sales to industrial
      customers were partially offset by lower KWH sales to residential and commercial
      customers. For the first nine months of 2006, higher KWH sales to industrial
      and
      commercial customers were partially offset by lower KWH sales to residential
      customers. Industrial KWH sales, for both periods, increased primarily due
      to
      the return of customers to Met-Ed from alternative suppliers. Sales by
      alternative suppliers as a percent of total industrial sales in Met-Ed’s
      franchise area decreased by 9.7 percentage points in the third quarter of 2006
      and 12.6 percentage points in the first nine months of 2006. Lower KWH sales
      to
      residential customers, for both periods of 2006, and to commercial customers,
      for the third quarter of 2006, primarily resulted from milder weather in 2006
      as
      compared with the same periods of 2005.





Revenues
      from
      distribution throughput essentially remained unchanged for the third quarter
      of
      2006 as compared with the same period of 2005. This was the result of higher
      composite unit prices being substantially offset by a decrease in total KWH
      deliveries. The decrease in KWH deliveries primarily resulted from milder
      weather in the third quarter of 2006 (a 19.8% decrease in cooling degree days)
      compared with the same period in 2005. For the first nine months of 2006,
      revenues from distribution throughput decreased by $1 million compared with
      the
      same period of 2005. A 1.3% decrease in KWH deliveries was partially offset
      by
      higher composite prices. KWH deliveries decreased as a result from milder
      weather in the first nine months of 2006 (a 17.1% decrease in cooling degree
      days and a 15.7% decrease in heating degree days) as compared with the same
      period in 2005.





For
      both periods of
      2006, transmission revenues increased primarily due to higher transmission
      prices, which also resulted in higher transmission expenses as discussed below.
      Rental revenues also increased by $3 million, for both periods of 2006, due
      to
      higher charges for the joint use of Met-Ed’s utility poles. In the first nine
      months of 2006, other revenues also increased due to a $2 million increase
      in the payment received in the first quarter of 2006 under a contract provision
      associated with the prior sale of TMI Unit 1, compared to the same period in
      2005. Under the contract, additional payments are received if subsequent energy
      prices rise above specified levels. This payment is credited to Met-Ed’s
      customers, resulting in no net earnings effect.








164





Changes
      in KWH sales
      by customer class in the third quarter and the first nine months of 2006
      compared with the same periods in 2005 are summarized in the following
      table:





**Three**
            
            **Nine****Changes
                in KWH Sales**
            
            **Months**
            
            **Months****Increase
                (Decrease)**Retail
                Electric Generation:Residential
            
            
            (1.9
            )%
            
            (1.9
            )%Commercial
            
            
            (0.2
            )%
            
            1.3
            %Industrial
            
            
            8.2
            %
            
            11.9
            %**Total
                Retail Electric Generation Sales**
            
            
            **1.3**
            **%**
            
            **2.8**
            **%**Distribution
                Deliveries:Residential
            
            
            (2.1
            )%
            
            (2.1
            )%Commercial
            
            
            (0.9
            )%
            
            0.4
            %Industrial
            
            
            (2.3
            )%
            
            (2.3
            )%**Total
                Distribution Deliveries**
            
            
            **(1.8**
            **)%**
            
            **(1.3**
            **)%**





*Expenses*




Total expenses decreased by $16 million and $28 million in the third quarter
      and
      the first nine months of 2006, respectively, compared with the same periods
      of
      2005. The following table presents changes from the prior year by expense
      category:





**Three**
            
            **Nine****Expenses
                - Changes**
            
            **Months**
            
            **Months****Increase
                (Decrease)**
            
            ***(In
                millions)***Purchased
                power costs
            
            $
            (2
            )
            $
            20Other
                operating costs
            
            
            27
            
            
            36Provision
                for
                depreciation
            
            
            1
            
            
            (1
            )Amortization
                of regulatory assets
            
            
            1
            
            
            3Deferral
                of
                new regulatory assets
            
            
            (44
            )
            
            (90
            )General
                taxes
            
            
            1
            
            
            4**Net
                decrease in expenses**
            
            $
            (16
            )
            $
            (28
            )





Purchased
      power
      costs decreased by $2 million in the third quarter of 2006 due to lower
      composite unit prices, partially offset by increased purchases to meet higher
      customer demand and a $10 million charge related to incremental NUG costs
      deferred in 2005 under a revised accounting methodology. For the first nine
      months of 2006, purchased power costs increased by $20 million due to increased
      purchases to meet higher customer demand and higher composite unit prices,
      offset by increased NUG cost deferrals.





Other
      operating
      costs increased for both periods primarily due to higher transmission expenses,
      which increased as a result of the higher transmission prices discussed above.
      The deferral of new regulatory assets, for both periods, reflected the
      May 4, 2006 PPUC approval of Met-Ed’s request to defer certain 2006
      transmission-related costs (see Regulatory Matters for further discussion).
      For
      both periods, general taxes increased primarily due to higher gross receipt
      taxes.





**Capital
      Resources and Liquidity**





Met-Ed’s
      cash
      requirements for the remainder of 2006 for expenses and construction
      expenditures are expected to be met with a combination of cash from operations
      and short-term credit arrangements.





*Changes
      in Cash
      Position*





As
      of September 30,
      2006, Met-Ed had $133,000 of cash and cash equivalents compared with $120,000
      as
      of December 31, 2005. The major sources for changes in these balances are
      summarized below.





165








*Cash
      Flows From
      Operating Activities*





Cash
      provided from
      operating activities in the first nine months of 2006 and 2005 were as
      follows:





**Nine
                Months Ended****September
                30,****Operating
                Cash Flows**
            
            **2006**
            
            **2005*****(In
                millions)***Cash
                earnings(1)
            
            $
            82
            
            $
            89Working
                capital and other
            
            
            (16
            )
            
            57Net
                cash
                provided from operating activities
            
            $
            66
            
            $
            146





(1) Cash
      earnings are a
      non-GAAP measure (see reconciliation below).





Cash
      earnings (in
      the table above) are not a measure of performance calculated in accordance
      with
      GAAP. Met-Ed believes that cash earnings is a useful financial measure because
      it provides investors and management with an additional means of evaluating
      its
      cash-based operating performance. Generally, a non-GAAP financial measure is
      a
      numerical measure of a company’s historical or future financial performance,
      financial position, or cash flows that either excludes or includes amounts,
      or
      is subject to adjustment that has the effect of excluding or including amounts,
      that are not normally excluded or included in the most directly comparable
      measure calculated and presented in accordance with GAAP. In addition, cash
      earnings (non-GAAP) are not defined under GAAP. Management believes presenting
      this non-GAAP measure provides useful information to investors in assessing
      Met-Ed’s operating performance from a cash perspective without the effects of
      material unusual economic events. Met-Ed’s management frequently references
      these non-GAAP financial measures in its decision-making, using them to
      facilitate historical and ongoing performance comparisons as well as comparisons
      to the performance of peer companies. These non-GAAP measures should be
      considered in addition to, and not as a substitute for, their most directly
      comparable financial measures prepared in accordance with GAAP.





**Nine
                Months Ended****September
                30,****Reconciliation
                of Cash Earnings**
            
            **2006**
            
            **2005*****(In
                millions)***Net
                income
                (GAAP)
            
            $
            83
            
            $
            33Non-cash
                charges (credits):Provision
                for
                depreciation
            
            
            31
            
            
            32Amortization
                of regulatory assets
            
            
            89
            
            
            87Deferred
                costs
                recoverable as regulatory assets
            
            
            (53
            )
            
            (49
            )Deferral
                of
                new regulatory assets
            
            
            (90
            )
            
            -Deferred
                income taxes and investment tax credits, net
            
            
            28
            
            
            (10
            )Other
                non-cash
                charges
            
            
            (6
            )
            
            (4
            )Cash
                earnings
                (Non-GAAP)
            
            $
            82
            
            $
            89





The
      $7 million
      decrease in cash earnings is described above under “Results of Operations.” The
      $73 million working capital change primarily resulted from an $86 million
      decrease in cash provided from the collection of receivables, a $22 million
      increase in cash collateral returned to suppliers, a $6 million increase in
      prepayments, and a $4 million decrease in other accrued liabilities, offset
      by
      $43 million in decreased outflows for accounts payable and a $2 million increase
      in accrued interest.





*Cash
      Flows From
      Financing Activities*





Net
      cash provided
      from financing activities was $12 million in first nine months of 2006 compared
      to $85 million in net cash used for financing activities in the same period
      of 2005. The increase primarily reflects a $120 million increase in
      short-term borrowings and a $39 million decrease in common stock dividend
      payments to FirstEnergy in the first nine months of 2006, offset by a $62
      million increase in long-term debt redemptions.





As
      of September 30,
      2006, Met-Ed had approximately $33 million of cash and temporary
      investments (which included short-term notes receivable from associated
      companies) and $257 million of short-term borrowings. Met-Ed has
      authorization from the FERC to incur short-term debt up to $250 million and
      authorization from the PPUC to incur money pool borrowings up to
      $300 million. In addition, Met-Ed has $80 million of available
      accounts receivable financing facilities as of September 30, 2006 through
      Met-Ed Funding LLC, Met-Ed’s wholly owned subsidiary. As a separate legal entity
      with separate creditors, Met-Ed Funding would have to satisfy its obligations
      to
      creditors before any of its remaining assets could be made available to Met-Ed.
      In June 2006, the facility was renewed until June 28, 2007. The annual
      facility fee is 0.125% on the entire finance limit. As of September 30, 2006
      the
      facility was drawn for $75 million.





166








Under
      the terms of
      Met-Ed’s senior note indenture, FMBs may no longer be issued so long as senior
      notes are outstanding. As of September 30, 2006, Met-Ed had the capability
      to issue $642 million of additional senior notes based upon FMB collateral.
      Met-Ed had no restrictions on the issuance of preferred stock.





On
      August 24, 2006,
      Met-Ed, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Penelec, FES and ATSI, as
      Borrowers, entered into a new $2.75 billion five-year revolving credit facility,
      which replaced the prior $2 billion credit facility. FirstEnergy may
      request an increase in the total commitments available under the new facility
      up
      to a maximum of $3.25 billion. Commitments
      under
      the new facility are available until August 24, 2011, unless the lenders
      agree, at the request of the Borrowers, to two additional one-year extensions.
      Generally, borrowings under the facility must be repaid within 364 days.
      Available amounts for each Borrower are subject to a specified sub-limit, as
      well as applicable regulatory and other limitations. Met-Ed’s
      borrowing
      limit under the facility is $250 million.





Under
      the revolving
      credit facility, Borrowers may request the issuance of LOCs expiring up to
      one
      year from the date of issuance. The stated amount of outstanding LOCs will
      count
      against total commitments available under the facility and against the
      applicable borrower’s borrowing sub-limit. Total unused borrowing capability
      under the existing credit facilities and accounts receivable financing
      facilities totaled $255 million as of September 30, 2006.





The
      revolving credit
      facility contains financial covenants requiring each Borrower to maintain a
      consolidated debt to total capitalization ratio of no more than 65%. As of
      September 30, 2006, Met-Ed’s debt to total capitalization as defined under
      the revolving credit facility was 38%.





The
      facility does
      not contain any provisions that either restrict Met-Ed’s ability to borrow or
      accelerate repayment of outstanding advances as a result of any change in its
      credit ratings. Pricing is defined in “pricing grids”, whereby the cost of funds
      borrowed under the facility is related to Met-Ed's credit ratings.





Met-Ed
      has the
      ability to borrow from its regulated affiliates and FirstEnergy to meet its
      short-term working capital requirements. FESC administers this money pool and
      tracks surplus funds of FirstEnergy and its regulated subsidiaries, as well
      as
      proceeds available from bank borrowings. Companies receiving a loan under the
      money pool agreements must repay the principal amount of such a loan, together
      with accrued interest, within 364 days of borrowing the funds. The rate of
      interest is the same for each company receiving a loan from the pool and is
      based on the average cost of funds available through the pool. The average
      interest rate for borrowings in the first nine months of 2006 was
      5.09%.





Met-Ed’s
      access to
      the capital markets and the costs of financing are dependent on the ratings
      of
      its securities and that of FirstEnergy. As of September 30, 2006, Met-Ed’s
      and FirstEnergy’s ratings outlook from S&P on all securities was stable. The
      ratings outlook from Moody’s and Fitch on all securities is
      positive.





*Cash
      Flows From
      Investing Activities*





In
      the final nine
      months of 2006, Met-Ed’s cash used for investing activities totaled
      $78 million, compared with $61 million in the same period of 2005. The
      increase primarily resulted from a $9 million increase in property
      additions and a $7 million increase in loans to associated companies.
      Expenditures for property additions primarily support Met-Ed’s energy delivery
      operations and reliability initiatives.





During
      the last
      quarter of 2006, capital requirements for property additions are expected to
      be
      about $15 million. This cash requirement is expected to be satisfied from a
      combination of internal cash and short-term credit arrangements.





Met-Ed's
      capital
      spending for the period 2006 through 2010 is expected to be about
      $365 million, of which approximately $81 million applies to 2006. The
      capital spending is primarily for property additions supporting the distribution
      of electricity.





167





**Market
      Risk Information**





Met-Ed
      uses various
      market risk sensitive instruments, including derivative contracts, primarily
      to
      manage the risk of price fluctuations. FirstEnergy’s Risk Policy Committee,
      comprised of members of senior management, provides general oversight to risk
      management activities.





*Commodity
      Price
      Risk*





Met-Ed
      is exposed to
      market risk primarily due to fluctuations in electricity, energy transmission,
      natural gas, coal, and emission prices. To manage the volatility relating to
      these exposures, it uses a variety of non-derivative and derivative instruments,
      including forward contracts, options, futures contracts, and swaps. The
      derivatives are used principally for hedging purposes. All derivatives that
      fall
      within the scope of SFAS 133 must be recorded at their fair value and marked
      to
      market. The majority of Met-Ed’s derivative hedging contracts qualify for the
      normal purchase and normal sale exception under SFAS 133. Contracts that are
      not
      exempt from such treatment include the power purchase agreements with NUG
      entities that were structured pursuant to the Public Utility Regulatory Policies
      Act of 1978. These non-trading contracts had been adjusted to fair value at
      the
      end of each quarter, with a corresponding regulatory asset recognized for
      above-market costs. On April 1, 2006, Met-Ed elected to apply the normal
      purchase and normal sale exception to certain NUG power purchase agreements
      having an above-market fair value of $1 million (included in “Other” in the
      table below) in accordance with guidance in DIG C20. The change in the fair
      value of commodity derivative contracts related to energy production during
      the
      third quarter and first nine months of 2006 is summarized in the following
      table:








**Three
                Months Ended**
            
            **Nine
                Months Ended****Increase
                (Decrease) in the Fair Value**
            **September
                30, 2006**
            
            **September
                30, 2006****of
                Commodity Derivative Contracts**
            **Non-Hedge**
            
            **Hedge**
            
            **Total**
            
            **Non-Hedge**
            
            **Hedge**
            
            **Total*****(In
                millions)*****Change
                in the Fair Value of****Commodity
                Derivative Contracts:**Outstanding
                net asset at beginning of period
            $
            23
            
            $
            -
            
            $
            23
            
            $
            27
            
            $
            -
            
            $
            27New
                contract
                value when entered
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Additions/change
                in value of existing contracts
            
            -
            
            
            -
            
            
            -
            
            
            4
            
            
            -
            
            
            4Change
                in
                techniques/assumptions
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Settled
                contracts
            
            -
            
            
            -
            
            
            -
            
            
            (9
            )
            
            -
            
            
            (9
            )Other
            
            -
            
            
            -
            
            
            -
            
            
            1
            
            
            -
            
            
            1**Net
                Assets - Derivative Contracts**
              **at
                End
                of Period****(1)**
            $
            23
            
            $
            -
            
            $
            23
            
            $
            23
            
            $
            -
            
            $
            23**Impact
                of Changes in Commodity Derivative Contracts****(2)**Income
                Statement effects (pre-tax)
            $
            -
            
            $
            -
            
            $
            -
            
            $
            (2
            )
            $
            -
            
            $
            (2
            )Balance
                Sheet
                effects:OCI
                (pre-tax)
            $
            -
            
            $
            -
            
            $
            -
            
            $
            -
            
            $
            -
            
            $
            -Regulatory
                liability
            $
            -
            
            $
            -
            
            $
            -
            
            $
            3
            
            $
            -
            
            $
            3





(1)  Includes
      $23 million
      in non-hedge commodity derivative contract, which is offset by a regulatory
      liability.


(2)  Represents
      the
      change in value of existing contracts, settled contracts and changes in
      techniques/assumptions.




Derivatives are included on the Consolidated Balance Sheet as of
      September 30, 2006 as follows:





**Balance
                Sheet Classification**
            
            **Non-Hedge**
            
            **Hedge**
            
            **Total*****(In
                millions)*****Non-Current-**Other
                deferred
                charges
            
            $
            23
            
            $
            -
            
            $
            23Other
                noncurrent liabilities
            
            
            -
            
            
            -
            
            
            -Net
                assets
            
            $
            23
            
            $
            -
            
            $
            23





The
      valuation of
      derivative contracts is based on observable market information to the extent
      that such information is available. In cases where such information is not
      available, Met-Ed relies on model-based information. The model provides
      estimates of future regional prices for electricity and an estimate of related
      price volatility. Met-Ed uses these results to develop estimates of fair value
      for financial reporting purposes and for internal management decision making.
      Sources of information for the valuation of commodity derivative contracts
      as of
      September 30, 2006 are summarized by year in the following
      table:





168











**Source
                of Information****Fair
                Value by Contract Year**
            
            **2006**(1)
            
            **2007**
            
            **2008**
            
            **2009**
            
            **2010**
            
            **Thereafter**
            
            **Total*****(In
                millions)***Other
                external
                sources(2)(3)
            
            $
            5
            
            $
            5
            
            $
            5
            
            $
            4
            
            $
            -
            
            $
            -
            
            $
            19Prices
                based
                on models(3)
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            4
            
            
            -
            
            
            4Total(3)
            
            $
            5
            
            $
            5
            
            $
            5
            
            $
            4
            
            $
            4
            
            $
            -
            
            $
            23





(1)  For
      the last quarter
      of 2006.


(2)  Broker
      quote
      sheets.


(3)  Includes
      $23 million
      from a non-hedge commodity derivative contract that is offset by a regulatory
      liability and does not affect earnings.





Met-Ed
      performs
      sensitivity analyses to estimate its exposure to the market risk of its
      commodity positions. A hypothetical 10% adverse shift in quoted market prices
      in
      the near term on both of Met-Ed’s trading and non-trading derivative instruments
      would not have had a material effect on its consolidated financial position
      or
      cash flows as of September 30, 2006. Met-Ed estimates that if energy
      commodity prices experienced an adverse 10% change, net income for the next
      twelve months would not change, as prices for all commodity positions are
      already above the contract price caps.





*Equity
      Price
      Risk*





Included
      in Met-Ed's
      nuclear decommissioning trusts are marketable equity securities carried at
      their
      market value of approximately  $153 million  and
      $142 million as of September 30, 2006 and December 31, 2005,
      respectively. A hypothetical 10% decrease in prices quoted by stock exchanges
      would result in a  $15 million
      reduction in fair value as of September 30, 2006.





**Regulatory
      Matters**




Regulatory assets are costs which have been authorized by the PPUC and the
      FERC
      for recovery from customers in future periods or for which authorization is
      probable. Without the probability of such authorization, costs currently
      recorded as regulatory assets would have been charged to income as incurred.
      All
      regulatory assets are expected to be recovered under the provisions of Met-Ed’s
      transition plan and rate restructuring plan. Met-Ed’s regulatory assets as of
      September 30, 2006 and December 31, 2005 were $365 million and
      $310 million, respectively.




A February 2002 Commonwealth Court of Pennsylvania decision affirmed the June
      2001 PPUC decision regarding approval of the FirstEnergy/GPU merger, remanded
      the issues of quantification and allocation of merger savings to the PPUC and
      denied Met-Ed and Penelec the rate relief initially approved in the PPUC
      decision. On October 2, 2003, the PPUC issued an order concluding that the
      Commonwealth Court reversed the PPUC’s June 2001 order in its entirety. In
      accordance with the PPUC's direction, Met-Ed and Penelec filed supplements
      to
      their tariffs that became effective in October 2003 and that reflected the
      CTC
      rates and shopping credits in effect prior to the June 2001 order. Met-Ed’s
      and Penelec’s combined portion of total net merger savings during 2001 - 2004 is
      estimated to be approximately $51 million. A procedural schedule was
      established by the ALJ on January 17, 2006 and the companies filed initial
      testimony on March 1, 2006. On May 4, 2006, the PPUC consolidated this
      proceeding with the April 10, 2006 comprehensive rate filing proceeding
      discussed below. Met-Ed and Penelec are unable to predict the outcome of this
      matter.




In an October 16, 2003 order, the PPUC approved June 30, 2004 as the
      date for Met-Ed's NUG trust fund refunds. The PPUC order also denied its
      accounting treatment request regarding the CTC rate/shopping credit swap by
      requiring Met-Ed to treat the stipulated CTC rates that were in effect from
      January 1, 2002 on a retroactive basis. On October 22, 2003, Met-Ed
      filed an Objection with the Commonwealth Court asking that the Court reverse
      this PPUC finding; a Commonwealth Court judge subsequently denied its Objection
      on October 27, 2003 without explanation. On October 31, 2003, Met-Ed
      filed an Application for Clarification of the Court order with the Commonwealth
      Court, a Petition for Review of the PPUC's October 2 and October 16,
      2003 Orders, and an Application for Reargument, if the judge, in his
      clarification order, indicates that Met-Ed's Objection was intended to be denied
      on the merits. The Reargument Brief before the Commonwealth Court was filed
      on
      January 28, 2005. Oral arguments were held on June 8, 2006. On July
      19, 2006, the Commonwealth Court issued its decision affirming the PPUC’s prior
      orders. Although the decision denied the appeal of Met-Ed, it had previously
      accounted for the treatment of costs required by the PPUC’s October 2003
      orders.





169




Met-Ed purchases a portion of its PLR requirements from FES through a wholesale
      power sales agreement. Under this agreement, FES retains the supply obligation
      and the supply profit and loss risk for the portion of power supply requirements
      not self-supplied by Met-Ed under its contracts with NUGs and other unaffiliated
      suppliers. The FES arrangement reduces Met-Ed's exposure to high wholesale
      power
      prices by providing power at a fixed price for their uncommitted PLR energy
      costs during the term of the agreement with FES. The wholesale power sales
      agreement with FES could automatically be extended for each successive calendar
      year unless any party elects to cancel the agreement by November 1 of the
      preceding year. On November 1, 2005, FES and the other parties thereto
      amended the agreement to provide FES the right in 2006 to terminate the
      agreement at any time upon 60 days notice. On April 7, 2006, the
      parties to the wholesale power sales agreement entered into a Tolling Agreement
      that arises out of FES’ notice to Met-Ed that FES elected to exercise its right
      to terminate the wholesale power sales agreement effective midnight
      December 31, 2006, because that agreement is not economically sustainable
      to FES.




In lieu of allowing such termination to become effective as of December 31,
      2006, the parties agreed, pursuant to the Tolling Agreement, to amend the
      wholesale power sales agreement to provide as follows:





1.  The
      termination
      provisions of the wholesale power sales agreement will be tolled for one year
      until December 31, 2007, provided that during such tolling
      period:





a.  FES
      will be
      permitted to terminate the wholesale power sales agreement at any time with
      sixty days written notice;


b.  Met-Ed
      will procure
      through arrangements other than the wholesale power sales agreement beginning
      December 1, 2006 and ending December 31, 2007, approximately 33% of
      the amounts of capacity and energy necessary to satisfy its PLR obligations
      for
      which Committed Resources (i.e., non-utility generation under contract to
      Met-Ed, Met-Ed-owned generating facilities, purchased power contracts and
      distributed generation) have not been obtained; and


c.  FES
      will not be
      obligated to supply additional quantities of capacity and energy in the event
      that a supplier of Committed Resources defaults on its supply
      agreement.





2.  During
      the tolling
      period, FES will not act as an agent for Met-Ed in procuring the services under
      1 (b) above; and





3.  The
      pricing
      provision of the wholesale power sales agreement shall remain unchanged provided
      Met-Ed complies with the provisions of the Tolling Agreement and any applicable
      provision of the wholesale power sales agreement.




In the event that FES elects not to terminate the wholesale power sales
      agreement effective midnight December 31, 2007, similar tolling agreements
      effective after December 31, 2007 are expected to be considered by FES for
      subsequent years if Met-Ed procures through arrangements other than the
      wholesale power sales agreement approximately 64%, 83% and 95% of the additional
      amounts of capacity and energy necessary to satisfy its PLR obligations for
      2008, 2009 and 2010, respectively, for which Committed Resources have not been
      obtained from the market. On September 26, 2006, Met-Ed successfully
      conducted a competitive RFP for 33% of its PLR obligation for which Committed
      Resources had not been obtained for the period December 1, 2006 through
      December 31, 2008.




The wholesale power sales agreement, as modified by the Tolling Agreement,
      requires Met-Ed to satisfy the portion of its PLR obligations currently supplied
      by FES from unaffiliated suppliers at prevailing prices, which are likely to
      be
      higher than the current price charged by FES under the current agreement and,
      as
      a result, Met-Ed’s purchased power costs could materially increase. If Met-Ed
      were to replace the entire FES supply at current market power prices without
      corresponding regulatory authorization to increase its generation prices to
      customers, it would likely incur a significant increase in operating expenses
      and experience a material deterioration in credit quality metrics. Under such
      a
      scenario, Met-Ed's credit profile would no longer be expected to support an
      investment grade rating for its fixed income securities. There can be no
      assurance, however, that if FES ultimately determines to terminate, further
      reduce, or significantly modify the agreement, timely regulatory relief will
      be
      granted by the PPUC pursuant to the April 10, 2006 comprehensive rate
      filing discussed below, or, to the extent granted, adequate to mitigate such
      adverse consequences.





170








Met-Ed
      made a
      comprehensive rate filing with the PPUC on April 10, 2006 that addresses a
      number of transmission, distribution and supply issues. If Met-Ed's preferred
      approach involving accounting deferrals is approved, the filing would increase
      annual revenues by $216 million. That filing includes, among other things,
      a request to charge customers for an increasing amount of market priced power
      procured through a CBP as the amount of supply provided under the existing
      FES
      agreement is phased out in accordance with the April 7, 2006 Tolling
      Agreement described above. Met-Ed also requested approval of the
      January 12, 2005 petition for the deferral of transmission-related costs
      discussed above, but only for those costs incurred during 2006. In this rate
      filing, Met-Ed also requested recovery of annual transmission and related costs
      incurred on or after January 1, 2007, plus the amortized portion of 2006
      costs over a ten-year period, along with applicable carrying charges, through
      an
      adjustable rider similar to that implemented in Ohio. Changes in the recovery
      of
      NUG expenses and the recovery of Met-Ed's non-NUG stranded costs are also
      included in the filing. The filing contemplates a reduction in distribution
      rates for Met-Ed of $37 million annually. The PPUC suspended the effective
      date (June 10, 2006) of these rate changes for seven months after the
      filing as permitted under Pennsylvania law. If the PPUC adopts the overall
      positions taken in the intervenors’ testimony as filed, this would have a
      material adverse effect on the financial statements of FirstEnergy and Met-Ed.
      Hearings were held in late August 2006 and all reply briefs were filed by
      October 6, 2006. The ALJ’s recommended decision is due by November 8, 2006
      and the PPUC decision is expected by January 12, 2007.





The
      annual goodwill
      impairment analysis performed in the third quarter of 2006 assumed management's
      best estimate of the rate increases that are expected to be granted in January
      2007 under Met-Ed’s comprehensive rate filing. If the PPUC authorizes less than
      the amounts assumed, an additional impairment analysis would be performed at
      that time and this could result in a future goodwill impairment loss that could
      be material. If rate relief were completely denied, it is estimated that
      approximately $604 million of Met-Ed’s goodwill would be impaired and
      written off. However, no adjustment to FirstEnergy’s goodwill on a consolidated
      basis would be recognized in that circumstance because the fair value of its
      regulated segment (which represents FirstEnergy's reporting unit to evaluate
      goodwill) would continue to exceed the carrying value of its investment in
      the
      segment.




As of September 30, 2006, Met-Ed's regulatory deferrals pursuant to the
      1998 Restructuring Settlement (including the Phase 2 Proceedings) and the
      FirstEnergy/GPU Merger Settlement Stipulation was $297 million. The PPUC
      recently conducted a review and audit of a modification to the NUG purchased
      power stranded cost accounting methodology for Met-Ed. On August 18, 2006,
      a
      PPUC Order was entered requiring Met-Ed to reflect the deferred NUG cost
      balances as if the stranded cost accounting methodology modification had not
      been implemented. As a result of the PPUC’s Order, Met-Ed recognized a pre-tax
      charge of approximately $10.3 million in the third quarter of 2006, representing
      incremental costs deferred under the revised methodology in 2005. Met-Ed
      continues to believe that the stranded cost accounting methodology modification
      is appropriate and filed a petition with the PPUC pursuant to its Order for
      authorization to reflect the stranded cost accounting methodology modification
      effective January 1, 1999.





On
      January 12,
      2005, Met-Ed filed, before the PPUC, a request for deferral of
      transmission-related costs beginning January 1, 2005. The OCA, OSBA, OTS,
      MEIUG, PICA, Allegheny Electric Cooperative and Pennsylvania Rural Electric
      Association all intervened in the case. Met-Ed sought to consolidate this
      proceeding (and modified its request to provide deferral of 2006
      transmission-related costs only) with the comprehensive rate filing it made
      on
      April 10, 2006 as described above. On May 4, 2006, the PPUC approved
      the modified request. Accordingly, Met-Ed has deferred approximately
      $90 million, representing transmission costs that were incurred from
      January 1, 2006 through September 30, 2006. On June 5, 2006, the OCA
      filed before the Commonwealth Court a petition for review of the PPUC’s approval
      of the deferral. On July 12, 2006, the Commonwealth Court granted the PPUC’s
      motion to quash the OCA’s appeal. The ratemaking treatment of the deferrals will
      be determined in the comprehensive rate filing proceeding discussed above.




On November 18, 2004, the FERC issued an order eliminating the RTOR for
      transmission service between the MISO and PJM regions. The FERC also ordered
      MISO, PJM and the transmission owners within MISO and PJM to submit compliance
      filings containing a SECA mechanism to recover lost RTOR revenues during a
      16-month transition period from load serving entities. The FERC issued orders
      in
      2005 setting the SECA for hearing. ATSI, JCP&L, Met-Ed, Penelec, and FES
      continue to be involved in the FERC hearings concerning the calculation and
      imposition of the SECA charges. The hearing was held in May 2006. Initial
      briefs were submitted on June 9, 2006, and reply briefs were filed on June
      27, 2006. The Presiding Judge issued an Initial Decision on August 10,
      2006, rejecting the compliance filings made by the RTOs and transmission owners,
      ruling on various issues and directing new compliance filings. This decision
      is
      subject to review and approval by the FERC. Briefs addressing the Initial
      Decision were filed on September 11, 2006 and October 20, 2006. A
      final order could be issued by the FERC by the end of 2006.





171








On January 31, 2005, certain PJM transmission owners made three filings
      with the FERC pursuant to a settlement agreement previously approved by the
      FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined
      in two of the filings. In the first filing, the settling transmission owners
      submitted a filing justifying continuation of their existing rate design within
      the PJM RTO. In the second filing, the settling transmission owners proposed
      a
      revised Schedule 12 to the PJM tariff designed to harmonize the rate
      treatment of new and existing transmission facilities. Interventions and
      protests were filed on February 22, 2005. In the third filing, Baltimore
      Gas and Electric Company and Pepco Holdings, Inc. requested a formula rate
      for
      transmission service provided within their respective zones. On May 31,
      2005, the FERC issued an order on these cases. First, it set for hearing the
      existing rate design and indicated that it will issue a final order within
      six
      months. American Electric Power Company, Inc. filed in opposition proposing
      to
      create a "postage stamp" rate for high voltage transmission facilities across
      PJM. Second, the FERC approved the proposed Schedule 12 rate harmonization.
      Third, the FERC accepted the proposed formula rate, subject to refund and
      hearing procedures. On June 30, 2005, the settling PJM transmission owners
      filed a request for rehearing of the May 31, 2005 order. On March 20,
      2006, a settlement was filed with FERC in the formula rate proceeding that
      generally accepts the companies' formula rate proposal. The FERC issued an
      order
      approving this settlement on April 19, 2006. Hearings in the PJM rate
      design case concluded in April 2006. On July 13, 2006, an Initial Decision
      was
      issued by the ALJ. The ALJ adopted the Trial Staff’s position that the cost of
      all PJM transmission facilities should be recovered through a postage stamp
      rate. The ALJ recommended an April 1, 2006 effective date for this change in
      rate design. If the FERC accepts this recommendation, the transmission rate
      applicable to many load zones in PJM would increase. FirstEnergy believes that
      significant additional transmission revenues would have to be recovered from
      the
      JCP&L, Met-Ed and Penelec transmission zones within PJM. JCP&L, Met-Ed
      and Penelec, as part of the Responsible Pricing Alliance, filed a brief
      addressing the Initial Decision on August 14, 2006 and September 5,
      2006. The case will be reviewed by the FERC with a decision anticipated in
      the
      fourth quarter of 2006.





See
      Note 11 to
      the consolidated financial statements for further details and a complete
      discussion of regulatory matters in Pennsylvania including a more detailed
      discussion of reliability initiatives, including actions by the PPUC that impact
      Met-Ed .





**Environmental
      Matters**




Met-Ed accrues environmental liabilities when it concludes that it is probable
      that it has an obligation for such costs and can reasonably determine the amount
      of such costs. Unasserted claims are reflected in Met-Ed’s determination of
      environmental liabilities and are accrued in the period that they are both
      probable and reasonably estimable.




Met-Ed has been named as a PRP at waste disposal sites, which may require
      cleanup under the Comprehensive Environmental Response, Compensation, and
      Liability Act of 1980. Allegations of disposal of hazardous substances at
      historical sites and the liability involved are often unsubstantiated and
      subject to dispute; however, federal law provides that all PRPs for a particular
      site are liable on a joint and several basis. Therefore, environmental
      liabilities that are considered probable have been recognized on the
      Consolidated Balance Sheet as of September 30, 2006, based on estimates of
      the total costs of cleanup, Met-Ed’s proportionate responsibility for such
      costs, and the financial ability of other unaffiliated entities to pay.




See Note 10(B) to the consolidated financial statements for further details
      and a complete discussion of environmental matters.





**Other
      Legal Proceedings**





*Power
      Outages
      and Related Litigation*




There are various lawsuits, claims (including claims for asbestos exposure)
      and
      proceedings related to Met-Ed’s normal business operations pending against
      Met-Ed. The other material items not otherwise discussed below are described
      in
      Note 10(C) to the consolidated financial statements.





172




On August 14, 2003, various states and parts of southern Canada experienced
      widespread power outages. The outages affected approximately 1.4 million
      customers in FirstEnergy's service area. The U.S. - Canada Power System Outage
      Task Force’s final report in April 2004 on the outages concluded, among other
      things, that the problems leading to the outages began in FirstEnergy’s Ohio
      service area. Specifically,
      the
      final report concluded, among other things, that the initiation of the
      August 14, 2003 power outages resulted from an alleged failure of both
      FirstEnergy and ECAR to assess and understand perceived inadequacies within
      the
      FirstEnergy system; inadequate situational awareness of the developing
      conditions; and a perceived failure to adequately manage tree growth in certain
      transmission rights of way. The Task Force also concluded that there was a
      failure of the interconnected grid's reliability organizations (MISO and PJM)
      to
      provide effective real-time diagnostic support. The final report is publicly
      available through the Department of Energy’s Web site (www.doe.gov). FirstEnergy
      believes that the final report does not provide a complete and comprehensive
      picture of the conditions that contributed to the August 14, 2003 power
      outages and that it does not adequately address the underlying causes of the
      outages. FirstEnergy remains convinced that the outages cannot be explained
      by
      events on any one utility's system. The final report contained 46
“recommendations to prevent or minimize the scope of future blackouts.”
Forty-five of those recommendations related to broad industry or policy matters
      while one, including subparts, related to activities the Task Force recommended
      be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct
      the
      causes of the August 14, 2003 power outages. FirstEnergy implemented
      several initiatives, both prior to and since the August 14, 2003 power
      outages, which were independently verified by NERC as complete in 2004 and
      were
      consistent with these and other recommendations and collectively enhance the
      reliability of its electric system. FirstEnergy’s implementation of these
      recommendations in 2004 included completion of the Task Force recommendations
      that were directed toward FirstEnergy. FirstEnergy is also proceeding with
      the
      implementation of the recommendations that were to be completed subsequent
      to
      2004 and will continue to periodically assess the FERC-ordered Reliability
      Study
      recommendations for forecasted 2009 system conditions, recognizing revised
      load
      forecasts and other changing system conditions which may impact the
      recommendations. Thus far, implementation of the recommendations has not
      required, nor is expected to require, substantial investment in new or material
      upgrades to existing equipment. The FERC or other applicable government agencies
      and reliability coordinators may, however, take a different view as to
      recommended enhancements or may recommend additional enhancements in the future
      as a result of adoption of mandatory reliability standards pursuant to the
      EPACT
      that could require additional material expenditures.




FirstEnergy is vigorously defending these actions, but cannot predict the
      outcome of any of these proceedings or whether any further regulatory
      proceedings or legal actions may be initiated against the Companies. Although
      unable to predict the impact of these proceedings, if FirstEnergy or its
      subsidiaries were ultimately determined to have legal liability in connection
      with these proceedings, it could have a material adverse effect on FirstEnergy's
      or its subsidiaries' financial condition, results of operations and cash flows.





**New
      Accounting Standards and Interpretations**





*SAB
                108 -
                “Considering the Effects of Prior Year Misstatements when Quantifying
                Misstatements in Current Year Financial
                Statements”*





In September 2006, the SEC issued SAB 108, which provides interpretive guidance
      on how registrants should quantify financial statement misstatements. There
      is
      currently diversity in practice, with the two commonly used methods to quantify
      misstatements being the “rollover” method (which primarily focuses on the income
      statement impact of misstatements) and the “iron curtain” method (which focuses
      on the balance sheet impact). SAB 108 requires registrants to use a dual
      approach whereby both of these methods are considered in evaluating the
      materiality of financial statement errors. Prior materiality assessments will
      need to be reconsidered using both the rollover and iron curtain methods. This
      guidance will be effective for Met-Ed in the fourth quarter of 2006. Met-Ed does
      not expect this Statement to have a material impact on its financial
      statements.





*SFAS
      157 - “Fair
      Value Measurements”*





In September 2006, the FASB issued SFAS 157, that establishes how companies
      should measure fair value when they are required to use a fair value measure
      for
      recognition or disclosure purposes under GAAP. This Statement addresses the
      need
      for increased consistency and comparability in fair value measurements and
      for
      expanded disclosures about fair value measurements. The key changes to current
      practice are: (1) the definition of fair value which focuses on an exit price
      rather than entry price; (2) the methods used to measure fair value such as
      emphasis that fair value is a market-based measurement, not an entity-specific
      measurement, as well as the inclusion of an adjustment for risk, restrictions
      and credit standing; and (3) the expanded disclosures about fair value
      measurements.





173








This Statement is effective for financial statements issued for fiscal years
      beginning after November 15, 2007, and interim periods within those years.
      Met-Ed is currently evaluating the impact of this Statement on its financial
      statements.





*SFAS
                158 -
                “Employers’ Accounting for Defined Benefit Pension and Other
                Postretirement Plans-an amendment of FASB Statements No. 87, 88,
                106, and
                132(R)”*





In September 2006, the FASB issued SFAS 158, which requires companies to
      recognize a net liability or asset to report the overfunded or underfunded
      status of their defined benefit pension and other postretirement benefit plans
      on their balance sheets and recognize changes in funded status in the year
      in
      which the changes occur through other comprehensive income. The funded status
      to
      be measured is the difference between plan assets at fair value and the benefit
      obligation. This Statement requires that gains and losses and prior service
      costs or credits, net of tax, that arise during the period be recognized as
      a
      component of other comprehensive income and not as components of net periodic
      benefit cost. Additional information should also be disclosed in the notes
      to
      the financial statements about certain effects on net periodic benefit cost
      for
      the next fiscal year that arise from delayed recognition of the gains or losses,
      prior service costs or credits, and transition asset or obligation. Upon the
      initial application of this Statement and subsequently, an employer should
      continue to apply the provisions in Statements 87, 88 and 106 in measuring
      plan
      assets and benefit obligations as of the date of its statement of financial
      position and in determining the amount of net periodic benefit cost. This
      Statement is effective for Met-Ed as of December 31, 2006. Met-Ed is
      currently evaluating the impact of this Statement on its financial
      statements.





*FSP
                FIN
                46(R)-6 - “Determining the Variability to Be Considered in Applying FASB
                interpretation No. 46(R)”*





In
      April 2006, the
      FASB issued FSP FIN 46(R)-6 that addresses how a reporting enterprise should
      determine the variability to be considered in applying FASB interpretation
      No.
      46 (revised December 2003). Met-Ed adopted FIN 46(R) in the first quarter of
      2004, consolidating VIE’s when Met-Ed or one of its subsidiaries is determined
      to be the VIE’s primary beneficiary. The variability that is considered in
      applying interpretation 46(R) affects the determination of (a) whether the
      entity is a VIE; (b) which interests are variable interests in the entity;
      and
      (c) which party, if any, is the primary beneficiary of the VIE. This FSP states
      that the variability to be considered shall be based on an analysis of the
      design of the entity, involving two steps:





Step
                1:
            Analyze
                the
                nature of the risks in the entityStep
                2:
            Determine
                the
                purpose(s) for which the entity was created and determine the variability
                the entity is designed to create and pass along to its interest
                holders.





After
      determining
      the variability to consider, the reporting enterprise can determine which
      interests are designed to absorb that variability. The guidance in this FSP
      is
      applied prospectively to all entities (including newly created entities) with
      which that enterprise first becomes involved and to all entities previously
      required to be analyzed under interpretation 46(R) when a reconsideration event
      has occurred after July 1, 2006. Met-Ed does not expect this Statement to
      have a material impact on its financial statements.





*FIN
      48 -
“Accounting for Uncertainty in Income Taxes - an interpretation of FASB
      Statement No. 109.”*





In
      June 2006, the
      FASB issued FIN 48 which clarifies the accounting for uncertainty in income
      taxes recognized in an enterprise’s financial statements in accordance with FASB
      Statement No. 109, “Accounting for Income Taxes.” This interpretation prescribes
      a recognition threshold and measurement attribute for the financial statement
      recognition and measurement of a tax position taken or expected to be taken
      on a
      tax return. This interpretation also provides guidance on derecognition,
      classification, interest, penalties, accounting in interim periods, disclosure
      and transition. The evaluation of a tax position in accordance with this
      interpretation will be a two-step process. The first step will determine if
      it
      is more likely than not that a tax position will be sustained upon examination
      and should therefore be recognized. The second step will measure a tax position
      that meets the more likely than not recognition threshold to determine the
      amount of benefit to recognize in the financial statements. This interpretation
      is effective for fiscal years beginning after December 15, 2006. Met-Ed is
      currently evaluating the impact of this Statement.








174





**PENNSYLVANIA
                  ELECTRIC COMPANY****CONSOLIDATED
                  STATEMENTS OF INCOME AND COMPREHENSIVE INCOME****(Unaudited)****Three
                  Months Ended**
              **Nine
                  Months Ended****September
                  30,**
              
              **September
                  30,****2006**
              
              **2005**
              
              **2006**
              
              **2005*****(In
                  thousands)*****REVENUES**
              
              $
              303,420
              
              $
              290,451
              
              $
              860,171
              
              $
              846,477**EXPENSES:**Purchased
                  power
              
              
              165,921
              
              
              178,090
              
              
              474,437
              
              
              467,639Other
                  operating costs
              
              
              65,165
              
              
              66,417
              
              
              151,640
              
              
              183,024Provision
                  for
                  depreciation
              
              
              11,828
              
              
              12,736
              
              
              36,269
              
              
              37,721Amortization
                  of regulatory assets
              
              
              13,060
              
              
              12,627
              
              
              40,854
              
              
              38,930Deferral
                  of
                  new regulatory assets
              
              
              (9,235
              )
              
              -
              
              
              (21,050
              )
              
              -General
                  taxes
              
              
              18,593
              
              
              17,552
              
              
              55,440
              
              
              51,892Total
                  expenses
              
              
              265,332
              
              
              287,422
              
              
              737,590
              
              
              779,206**OPERATING
                  INCOME**
              
              
              38,088
              
              
              3,029
              
              
              122,581
              
              
              67,271**OTHER
                  INCOME (EXPENSE):**Miscellaneous
                  income
              
              
              2,182
              
              
              2,088
              
              
              6,179
              
              
              3,356Interest
                  expense
              
              
              (11,840
              )
              
              (9,841
              )
              
              (33,975
              )
              
              (29,579
              )Capitalized
                  interest
              
              
              363
              
              
              285
              
              
              1,132
              
              
              674Total
                  other
                  income (expense)
              
              
              (9,295
              )
              
              (7,468
              )
              
              (26,664
              )
              
              (25,549
              )**INCOME
                  (LOSS) BEFORE INCOME TAXES**
              
              
              28,793
              
              
              (4,439
              )
              
              95,917
              
              
              41,722**INCOME
                  TAX EXPENSE (BENEFIT)**
              
              
              10,733
              
              
              (2,070
              )
              
              39,251
              
              
              16,870**NET
                  INCOME (LOSS)**
              
              
              18,060
              
              
              (2,369
              )
              
              56,666
              
              
              24,852**OTHER
                  COMPREHENSIVE INCOME (LOSS):**Unrealized
                  gain on derivative hedges
              
              
              17
              
              
              17
              
              
              49
              
              
              49Unrealized
                  gain (loss) on available for sale securities
              
              
              14
              
              
              18
              
              
              (4
              )
              
              (3
              )Other
                  comprehensive income
              
              
              31
              
              
              35
              
              
              45
              
              
              46Income
                  tax
                  expense related to othercomprehensive
                  income
              
              
              13
              
              
              20
              
              
              20
              
              
              20Other
                  comprehensive income, net of tax
              
              
              18
              
              
              15
              
              
              25
              
              
              26**TOTAL
                  COMPREHENSIVE INCOME (LOSS)**
              
              $
              18,078
              
              $
              (2,354
              )
              $
              56,691
              
              $
              24,878The
                  preceding
                  Notes to Consolidated Financial Statements as they relate to Pennsylvania
                  Electric Company are an integral part of these
                  statements.
   175
  **PENNSYLVANIA
                      ELECTRIC COMPANY****CONSOLIDATED
                      BALANCE SHEETS****(Unaudited)****September
                      30,**
                  
                  **December
                      31,****2006**
                  
                  **2005*****(In
                      thousands)*****ASSETS****CURRENT
                      ASSETS:**Cash
                      and cash
                      equivalents
                  
                  
                  $
                  47
                  
                  $
                  35Receivables-Customers
                      (less accumulated provisions of $3,920,000 and $4,184,000,respectively,
                      for uncollectible accounts)
                  
                  
                  
                  122,232
                  
                  
                  129,960Associated
                      companies
                  
                  
                  
                  5,208
                  
                  
                  18,626Other
                  
                  
                  
                  11,228
                  
                  
                  12,800Notes
                      receivable from associated companies
                  
                  
                  
                  20,599
                  
                  
                  17,624Prepayments
                      and other
                  
                  
                  
                  10,912
                  
                  
                  7,936170,226
                  
                  
                  186,981**UTILITY
                      PLANT:**In
                      service
                  
                  
                  
                  2,119,123
                  
                  
                  2,043,885Less
                      -
                      Accumulated provision for depreciation
                  
                  
                  
                  801,695
                  
                  
                  784,4941,317,428
                  
                  
                  1,259,391Construction
                      work in progress
                  
                  
                  
                  21,704
                  
                  
                  30,8881,339,132
                  
                  
                  1,290,279**OTHER
                      PROPERTY AND INVESTMENTS:**Nuclear
                      plant
                      decommissioning trusts
                  
                  
                  
                  120,107
                  
                  
                  113,368Non-utility
                      generation trusts
                  
                  
                  
                  98,864
                  
                  
                  96,761Other
                  
                  
                  
                  532
                  
                  
                  918219,503
                  
                  
                  211,047**DEFERRED
                      CHARGES AND OTHER ASSETS:**Goodwill
                  
                  
                  
                  873,819
                  
                  
                  882,344Prepaid
                      pension costs
                  
                  
                  
                  93,643
                  
                  
                  89,637Other
                  
                  
                  
                  36,258
                  
                  
                  38,2891,003,720
                  
                  
                  1,010,270$
                  2,732,581
                  
                  $
                  2,698,577**LIABILITIES
                      AND CAPITALIZATION****CURRENT
                      LIABILITIES:**Short-term
                      borrowings-Associated
                      companies
                  
                  
                  $
                  216,437
                  
                  $
                  261,159Other
                  
                  
                  
                  66,000
                  
                  
                  -Accounts
                      payable-Associated
                      companies
                  
                  
                  
                  12,429
                  
                  
                  33,770Other
                  
                  
                  
                  44,063
                  
                  
                  38,277Accrued
                      taxes
                  
                  
                  
                  17,864
                  
                  
                  27,905Accrued
                      interest
                  
                  
                  
                  14,373
                  
                  
                  8,905Other
                  
                  
                  
                  19,489
                  
                  
                  19,756390,655
                  
                  
                  389,772**CAPITALIZATION:**Common
                      stockholder's equity-Common
                      stock,
                      $20 par value, authorized 5,400,000 shares-5,290,596
                      shares outstanding
                  
                  
                  
                  105,812
                  
                  
                  105,812Other
                      paid-in
                      capital
                  
                  
                  
                  1,197,480
                  
                  
                  1,202,551Accumulated
                      other comprehensive loss
                  
                  
                  
                  (284
                  )
                  
                  (309
                  )Retained
                      earnings
                  
                  
                  
                  77,489
                  
                  
                  25,823Total
                      common
                      stockholder's equity
                  
                  
                  
                  1,380,497
                  
                  
                  1,333,877Long-term
                      debt
                      and other long-term obligations
                  
                  
                  
                  477,104
                  
                  
                  476,5041,857,601
                  
                  
                  1,810,381**NONCURRENT
                      LIABILITIES:**Regulatory
                      liabilities
                  
                  
                  
                  127,375
                  
                  
                  162,937Accumulated
                      deferred income taxes
                  
                  
                  
                  120,185
                  
                  
                  106,871Retirement
                      benefits
                  
                  
                  
                  107,860
                  
                  
                  102,046Asset
                      retirement obligations
                  
                  
                  
                  75,740
                  
                  
                  72,295Other
                  
                  
                  
                  53,165
                  
                  
                  54,275484,325
                  
                  
                  498,424**COMMITMENTS
                    AND CONTINGENCIES (Note 10)**$
                  2,732,581
                  
                  $
                  2,698,577The
                      preceding
                      Notes to Consolidated Financial Statements as they relate to
                      Pennsylvania
                      Electric Company are an integral part of these balance
                      sheets.
 
 176
  **PENNSYLVANIA
                    ELECTRIC COMPANY****CONSOLIDATED
                    STATEMENTS OF CASH FLOWS****(Unaudited)****Nine
                    Months Ended****September
                    30,****2006**
                
                **2005*****(In
                    thousands)*****CASH
                    FLOWS FROM OPERATING ACTIVITIES:**Net
                    income
                
                $
                56,666
                
                $
                24,852Adjustments
                    to
                    reconcile net income to net cash from operating activities
                    -Provision
                    for
                    depreciation
                
                
                36,269
                
                
                37,721Amortization
                    of regulatory assets
                
                
                40,854
                
                
                38,930Deferral
                    of
                    new regulatory assets
                
                
                (21,050
                )
                
                -Deferred
                    costs
                    recoverable as regulatory assets
                
                
                (56,272
                )
                
                (41,301
                )Deferred
                    income taxes and investment tax credits, net
                
                
                14,518
                
                
                (2,765
                )Accrued
                    retirement benefit obligations
                
                
                1,808
                
                
                3,005Accrued
                    compensation, net
                
                
                999
                
                
                (1,695
                )Decrease
                    (increase) in operating assets -Receivables
                
                
                22,719
                
                
                97,130Prepayments
                    and other current assets
                
                
                (2,977
                )
                
                (8,620
                )Increase
                    (decrease) in operating liabilities -Accounts
                    payable
                
                
                (15,555
                )
                
                (15,671
                )Accrued
                    taxes
                
                
                (9,841
                )
                
                11,235Accrued
                    interest
                
                
                5,468
                
                
                5,594Other
                
                
                (2,188
                )
                
                4,433Net
                    cash
                    provided from operating activities
                
                
                71,418
                
                
                152,848**CASH
                    FLOWS FROM FINANCING ACTIVITIES:**New
                    Financing
                    -Short-term
                    borrowings, net
                
                
                21,278
                
                
                -Redemptions
                    and Repayments -Long-term
                    debt
                
                
                -
                
                
                (11,534
                )Short-term
                    borrowings, net
                
                
                -
                
                
                (51,747
                )Dividend
                    Payments -Common
                    stock
                
                
                (5,000
                )
                
                (32,000
                )Net
                    cash
                    provided from (used for) financing activities
                
                
                16,278
                
                
                (95,281
                )**CASH
                    FLOWS FROM INVESTING ACTIVITIES:**Property
                    additions
                
                
                (81,228
                )
                
                (61,680
                )Loan
                    repayments from (loans to) associated companies, net
                
                
                (2,976
                )
                
                5,724Proceeds
                    from
                    nuclear decommissioning trust fund sales
                
                
                66,781
                
                
                59,820Investments
                    in
                    nuclear decommissioning trust funds
                
                
                (66,781
                )
                
                (59,820
                )Other,
                    net
                
                
                (3,480
                )
                
                (1,612
                )Net
                    cash used
                    for investing activities
                
                
                (87,684
                )
                
                (57,568
                )Net
                    increase
                    (decrease) in cash and cash equivalents
                
                
                12
                
                
                (1
                )Cash
                    and cash
                    equivalents at beginning of period
                
                
                35
                
                
                36Cash
                    and cash
                    equivalents at end of period
                
                $
                47
                
                $
                35The
                    preceding
                    Notes to Consolidated Financial Statements as they relate to
                    Pennsylvania
                    Electric Company are an integral part of these
                    statements.
   177













***Report
      of Independent Registered Public Accounting Firm***





























To
      the Stockholder
      and Board of


Directors
      of
      Pennsylvania Electric Company:





We
      have reviewed the
      accompanying consolidated balance sheet of Pennsylvania Electric Company and
      its
      subsidiaries as of September 30, 2006, and the related consolidated statements
      of income and comprehensive income for each of the three-month and nine-month
      periods ended September 30, 2006 and 2005 and the consolidated statements of
      cash flows for the nine-month periods ended September 30, 2006 and 2005. These
      interim financial statements are the responsibility of the Company’s
      management.





We
      conducted our
      review in accordance with the standards of the Public Company Accounting
      Oversight Board (United States). A review of interim financial information
      consists principally of applying analytical procedures and making inquiries
      of
      persons responsible for financial and accounting matters. It is substantially
      less in scope than an audit conducted in accordance with the standards of the
      Public Company Accounting Oversight Board, the objective of which is the
      expression of an opinion regarding the financial statements taken as a whole.
      Accordingly, we do not express such an opinion.





Based
      on our review,
      we are not aware of any material modifications that should be made to the
      accompanying consolidated interim financial statements for them to be in
      conformity with accounting principles generally accepted in the United States
      of
      America.





We
      have previously
      audited, in accordance with the standards of the Public Company Accounting
      Oversight Board (United States), the consolidated balance sheet as of December
      31, 2005, and the related consolidated statements of income, capitalization,
      common stockholder’s equity, preferred stock, cash flows and taxes for the year
      then ended (not presented herein), and in our report [which contained references
      to the Company’s change in its method of accounting for asset retirement
      obligations as of January 1, 2003 and conditional asset retirement obligations
      as of December 31, 2005 as discussed in Note 2(G) and Note 9 to those
      consolidated financial statements] dated February 27, 2006, we expressed an
      unqualified opinion on those consolidated financial statements. In our opinion,
      the information set forth in the accompanying consolidated balance sheet as
      of
      December 31, 2005, is fairly stated in all material respects in relation to
      the
      consolidated balance sheet from which it has been derived.





PricewaterhouseCoopers
                LLP
              Cleveland,
                Ohio
              October
                31,
                2006











178





**PENNSYLVANIA
      ELECTRIC COMPANY**





**MANAGEMENT’S
      DISCUSSION AND** **** **ANALYSIS
      OF**


**RESULTS
      OF
      OPERATIONS** **** **AND
      FINANCIAL CONDITION**











Penelec
      is a wholly
      owned electric utility subsidiary of FirstEnergy. Penelec conducts business
      in
      northern, western and south central Pennsylvania, providing regulated
      transmission and distribution services. Penelec also provides generation
      services to those customers electing to retain Penelec as their power supplier.





**Results
      of Operations**





Net
      income in the
      third quarter of 2006 increased to $18 million, compared to a $2 million
      net loss in the third quarter of 2005. The increase in net income resulted
      from
      the deferral of new regulatory assets, higher revenues and lower purchased
      power
      costs which were partially offset by higher general taxes and interest expense.
      In the first nine months of 2006, net income increased to $57 million, compared
      to $25 million in the first nine months of 2005. The increase in net income
      resulted from the deferral of new regulatory assets, higher revenues and lower
      other operating costs which were partially offset by higher purchased power
      costs, general taxes and interest expense, as discussed below.





*Revenues*





Revenues
      increased
      by $13 million in the third quarter of 2006 and $14 million in the first nine
      months of 2006, compared to the same periods of 2005. The increase in the third
      quarter of 2006 was primarily due to higher retail generation revenues and
      transmission revenues. The increase in the
      first nine months of 2006 was due primarily to higher retail generation revenues
      partially offset by lower transmission and distribution revenues. Retail
      generation revenues increased by $10 million in the third quarter of 2006 and
      $33 million for the first nine months of 2006 primarily due to higher KWH sales
      to industrial customers and higher composite unit prices in all customer
      classes. Industrial sales increased $6 million for the third quarter of 2006
      and
      $21 million for the first nine months of 2006 primarily due to the return of
      customers from alternative suppliers. Generation service provided by alternative
      suppliers as a percent of total industrial sales in Penelec’s service area
      decreased by 7.2 percentage points and 11.2 percentage points in the third
      quarter and the first nine months of 2006, respectively, compared with the
      corresponding periods of 2005 . Higher
      composite
      unit prices also increased generation revenues from residential customers by
      $1 million and $4 million and from commercial customers by $3 million
      and $8 million in the third quarter and first nine months of 2006, respectively.





Distribution
      revenues were essentially unchanged in the third quarter of 2006 compared with
      the same period of 2005. This occurred as a result of the increase from higher
      composite unit prices substantially offset by a 1.1% decrease in KWH deliveries.
      The decrease in KWH deliveries primarily resulted from the milder weather in
      the
      third quarter of 2006 (a 16.5% decrease in cooling degree days) compared to
      the
      same period in 2005. For the first nine months of 2006, distribution revenues
      decreased $3 million due to a 1.6% decrease in KWH deliveries partially offset
      by higher composite unit prices. Reduced KWH deliveries reflected milder weather
      in the first nine months of 2006 (a 22.9% decrease in cooling degree days and
      a
      12.0% decrease in heating degree days) compared with the same period in
      2005.





Transmission
      revenues increased by $2 million in the third quarter of 2006 due to Penelec
      exercising their right for additional auction revenue rights beginning in June
      2006 compared to the same time period in 2005. For the first nine months of
      2006, transmission revenues decreased $18 million due to lower transmission
      load
      requirements and lower prices. The decreased loads for the first nine months
      of
      2006 (and related lower congestion revenues) resulted from milder weather
      conditions, as discussed above, and also resulted in decreased transmission
      expenses discussed further below. For
      the first nine
      months of 2006, other revenues also increased by $1 million for a payment
      received in the first quarter of 2006 under a contract provision associated
      with
      the prior sale of TMI Unit 1. Under the contract, additional payments are
      received if subsequent energy prices rise above specified levels, which
      occurred. This payment was credited to Penelec’s customers, resulting in no net
      earnings effect.





179








Changes
      in KWH sales
      by customer class in the third quarter and first nine months of 2006 compared
      to
      the respective periods in 2005 are summarized in the following
      table:





**Three**
            
            **Nine****Changes
                in KWH Sales**
            
            **Months**
            
            **Months****Increase
                (Decrease)**Retail
                Electric Generation:Residential
            
            
            (2.5
            )%
            
            (2.2
            )%Commercial
            
            
            (0.2
            )%
            
            (0.5
            )%Industrial
            
            
            8.8
            %
            
            12.8
            %**Total
                Retail Electric Generation Sales**
            
            
            **1.6**
            **%**
            
            **2.7**
            **%**Distribution
                Deliveries:Residential
            
            
            (2.7
            )%
            
            (2.4
            )%Commercial
            
            
            (0.8
            )%
            
            (1.4
            )%Industrial
            
            
            (0.1
            )%
            
            (1.2
            )%**Total
                Distribution Deliveries**
            
            
            **(1.1**
            **)%**
            
            **(1.6**
            **)%**





*Expenses*





Total
      expenses
      decreased by $22 million or 7.7% in the third quarter of 2006 and $42 million
      or
      5.3% in the first nine months of 2006 compared with the same periods in 2005.
      The following table presents changes from the prior year by expense category:





**Three**
            
            **Nine****Expenses
                Changes**
            
            **Months**
            
            **Months*****(In
                millions)*****Increase
                (Decrease)**Purchased
                power costs
            
            $
            (12
            )
            $
            7Other
                operating costs
            
            
            (1
            )
            
            (31
            )Provision
                for
                depreciation
            
            
            (1
            )
            
            (2
            )Amortization
                of regulatory assets
            
            
            -
            
            
            2Deferral
                of
                new regulatory assets
            
            
            (9
            )
            
            (21
            )General
                taxes
            
            
            1
            
            
            3**Net
                decrease in expenses**
            
            $
            (22
            )
            $
            (42
            )





Purchased
      power
      costs decreased due to increased NUG cost deferrals of $11 million and a
      slight decrease of $1 million in purchased power costs due to lower
      composite unit prices, partially offset by increased volumes purchased to meet
      higher customer load. The nine month increase in purchased power costs was
      due
      to increased purchases to meet higher customer load and higher composite unit
      prices. This increase was partially offset by higher NUG cost deferrals of
      $15 million for the first nine months of 2006.





Reduced
      other
      operating costs in the third quarter of 2006 compared to the same period in
      2005
      were due to lower transmission expenses resulting from lower congestion charges.
      Partially offsetting these lower transmission were increased labor expenses
      due
      to higher levels of maintenance activities in the third quarter of 2006 for
      energy delivery operations and reliability initiatives compared to higher levels
      of construction activities in the third quarter of 2005. Other operating costs
      decreased the first nine months of 2006 compared to the same period of 2005
      due
      primarily to lower transmission expenses resulting from lower congestion
      charges. Expenses were further reduced due to higher levels of construction
      activities in the first nine months of 2006 compared to a higher level of
      maintenance activities for the same period of 2005. The deferral of new
      regulatory assets in 2006 reflected the May 4, 2006 PPUC approval of Penelec’s
      request to defer certain 2006 transmission-related costs (see Regulatory Matters
      for further discussion). For
      both periods,
      general taxes increased primarily due to higher Pennsylvania gross receipt
      taxes.





**Capital
      Resources and Liquidity** ****





Penelec’s
      cash
      requirements for the remainder of 2006 for expenses, construction expenditures
      and scheduled debt maturities, are expected to be met by a combination of cash
      from operations and short-term credit arrangements.





180








*Changes
      in Cash
      Position*





As
      of September 30,
      2006, Penelec had $47,000 of cash and cash equivalents compared with $35,000
      as
      of December 31, 2005. The major sources of changes in these balances are
      summarized below.





*Cash
      Flows From
      Operating Activities*





Cash
      provided from
      operating activities in the first nine months of 2006 and 2005 were as follows:





**Nine
                Months Ended****September
                30,****Operating
                Cash Flows**
            
            **2006**
            
            **2005*****(In
                millions)***Cash
                earnings(1)
            
            $
            74
            
            $
            59Working
                capital and other
            
            
            (3
            )
            
            94Net
                cash
                provided from operating activities
            
            $
            71
            
            $
            153





(1) Cash earnings are a
      non-GAAP measure (see reconciliation below).





Cash
      earnings (in
      the table above) are not a measure of performance calculated in accordance
      with
      GAAP. Penelec believes that cash earnings is a useful financial measure because
      it provides investors and management with an additional means of evaluating
      its
      cash-based operating performance. Generally, a non-GAAP financial measure is
      a
      numerical measure of a company’s historical or future financial performance,
      financial position, or cash flows that either excludes or includes amounts,
      or
      is subject to adjustment that has the effect of excluding or including amounts,
      that are not normally excluded or included in the most directly comparable
      measure calculated and presented in accordance with GAAP. In addition, cash
      earnings (non-GAAP) are not defined under GAAP. Management believes presenting
      this non-GAAP measure provides useful information to investors in assessing
      Penelec’s operating performance from a cash perspective without the effects of
      material unusual economic events. Penelec’s management frequently references
      these non-GAAP financial measures in its decision-making, using them to
      facilitate historical and ongoing performance comparisons as well as comparisons
      to the performance of peer companies. These non-GAAP measures should be
      considered in addition to, and not as a substitute for, their most directly
      comparable financial measures prepared in accordance with GAAP.




**Nine
                Months Ended****September
                30,****Reconciliation
                of Cash Earnings**
            
            **2006**
            
            **2005*****(In
                millions)***Net
                income
                (GAAP)
            
            $
            57
            
            $
            25Non-cash
                charges (credits):Provision
                for
                depreciation
            
            
            36
            
            
            38Amortization
                of regulatory assets
            
            
            41
            
            
            39Deferral
                of
                new regulatory assets
            
            
            (21
            )
            
            -Deferred
                costs
                recoverable as regulatory assets
            
            
            (56
            )
            
            (41
            )Deferred
                income taxes and investment tax credits, net
            
            
            14
            
            
            (3
            )Other
                non-cash
                items
            
            
            3
            
            
            1Cash
                earnings
                (Non-GAAP)
            
            $
            74
            
            $
            59





The
      $15 million
      increase in cash earnings is described above under “Results of Operations.” The
      $97 million change from working capital primarily resulted from a decrease
      of $74 million in cash provided from the collection of receivables and a
      $21 million decrease in accrued taxes.





*Cash
      Flows From
      Financing Activities*





Net
      cash provided
      from financing activities was $16 million in the first nine months of 2006
      compared to net cash used for financing activities of $95 million in the
      first nine months of 2005. The change reflects a $73 million increase in
      short-term borrowings, a $27 million reduction in common stock dividend
      payments to FirstEnergy and an $11 million decrease in long-term debt
      redemptions.





181








Penelec
      had
      approximately $21 million of cash and temporary investments (which includes
      short-term notes receivable from associated companies) and approximately $282
      million of short-term indebtedness as of September 30, 2006. Penelec has
      authorization from the FERC to incur short-term debt of up to $250 million
      and
      authorization from the PPUC to incur money pool borrowings of up to
      $300 million. In addition, Penelec has $75 million of available
      accounts receivable financing facilities as of September 30, 2006 through
      Penelec Funding, Penelec's wholly owned subsidiary. As a separate legal entity
      with separate creditors, Penelec Funding would have to satisfy its obligations
      to creditors before any of its remaining assets could be made available to
      Penelec. As of September 30, 2006 the facility was drawn for
      $66 million. The annual facility fee is 0.125% on the entire finance
      limit.





Penelec
      will not
      issue FMB other than as collateral for senior notes, since its senior note
      indentures prohibit (subject to certain exceptions) Penelec from issuing any
      debt which is senior to the senior notes. As of September 30, 2006, Penelec
      had
      the ability to issue $60 million of additional senior notes based upon FMB
      collateral. Penelec has no restrictions on the issuance of preferred
      stock.





On
      August 24, 2006,
      Penelec ,
      FirstEnergy, OE,
      Penn, CEI, TE, JCP&L, Met-Ed, FES and ATSI, as Borrowers, entered into a new
      $2.75 billion five-year revolving credit facility, which replaced the prior
      $2 billion credit facility. FirstEnergy may request an increase in the total
      commitments available under the new facility up to a maximum of $3.25 billion. Commitments
      under
      the new facility are available until August 24, 2011, unless the lenders
      agree, at the request of the Borrowers, to two additional one-year extensions.
      Generally, borrowings under the facility must be repaid within 364 days.
      Available amounts for each Borrower are subject to a specified sub-limit, as
      well as applicable regulatory and other limitations. Penelec's
      borrowing
      limit under the facility is $250 million.





Under
      the revolving
      credit facility, borrowers may request the issuance of LOCs expiring up to
      one
      year from the date of issuance. The stated amount of outstanding LOCs will
      count
      against total commitments available under the facility and against the
      applicable borrower’s borrowing sub-limit. Total unused borrowing capability
      under existing credit facilities and accounts receivable financing facilities
      totaled $259 million.





The
      revolving credit
      facility contains financial covenants requiring each borrower to maintain a
      consolidated debt to total capitalization ratio of no more than 65%, measured
      at
      the end of each fiscal quarter. As of September 30, 2006, Penelec’s debt to
      total capitalization as defined under the revolving credit facility was
      35%.





The
      facility does
      not contain any provisions that either restrict Penelec's ability to borrow
      or
      accelerate repayment of outstanding advances as a result of any change in its
      credit ratings. Pricing is defined in “pricing grids”, whereby the cost of funds
      borrowed under the facility is related to Penelec's credit ratings.





Penelec has the ability to borrow from its regulated affiliates and FirstEnergy
      to meet its short-term working capital requirements. FESC administers this
      money
      pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries.
      Companies receiving a loan under the money pool agreements must repay the
      principal, together with accrued interest, within 364 days of borrowing the
      funds. The rate of interest is the same for each company receiving a loan from
      the pool and is based on the average cost of funds available through the pool.
      The average interest rate for borrowings under these arrangements in the first
      nine months of 2006 was 5.09%.





Penelec’s
      access to
      capital markets and costs of financing are dependent on the ratings of its
      securities and that of FirstEnergy. The ratings outlook from S&P on all
      securities is stable. The ratings outlook from Moody's and Fitch on all
      securities is positive.





*Cash
      Flows From
      Investing Activities*





In
      the first nine
      months of 2006, net cash used for investing activities totaled $88 million
      compared to $58 million in the first nine months of 2005. The increase primarily
      resulted from a $20 million increase in property additions and a $9 million
      increase in loans to associated companies. Expenditures for property additions
      primarily support Penelec’s energy delivery operations and reliability
      initiatives.





During
      the last
      quarter of 2006, capital requirements for property additions are expected to
      be
      approximately $24 million. This cash requirement is expected to be
      satisfied from a combination of internal cash and short-term credit
      arrangements.





Penelec’s
      capital
      spending for the period 2006-2010 is expected to be approximately
      $494 million, of which approximately $108 million applies to 2006. The
      capital spending is primarily for property additions supporting the distribution
      of electricity.





182








**Market
      Risk Information** ****





Penelec
      uses various
      market risk sensitive instruments, including derivative contracts, primarily
      to
      manage the risk of price fluctuations. FirstEnergy’s Risk Policy Committee,
      comprised of members of senior management, provides general oversight to risk
      management activities.





*Commodity
      Price
      Risk*





Penelec
      is exposed
      to market risk primarily due to fluctuations in electricity, energy
      transmission, natural gas, coal, and emission prices. To manage the volatility
      relating to these exposures, Penelec uses a variety of non-derivative and
      derivative instruments, including forward contracts, options, futures contracts
      and swaps. The derivatives are used principally for hedging purposes. All
      derivatives that fall within the scope of SFAS 133 must be recorded at
      their fair value and marked to market. The majority of Penelec’s derivative
      hedging contracts qualify for the normal purchase and normal sale exception
      under SFAS 133. Contracts that are not exempt from such treatment include
      the power purchase agreements with NUG entities that were structured pursuant
      to
      the Public Utility Regulatory Policies Act of 1978. These
      non-trading
      contracts had been adjusted to fair value at the end of each quarter, with
      a
      corresponding regulatory asset recognized for above-market costs. On April
      1,
      2006, Penelec elected to apply the normal purchase and normal sale exception
      to
      certain NUG power purchase agreements having a fair value of $14 million
      (included in “Other” in the table below) in accordance with guidance in DIG C20.
      The change in the fair value of commodity derivative contracts related to energy
      production during the third quarter and first nine months of 2006 is summarized
      in the following table:





**Three
                Months Ended**
            
            **Nine
                Months Ended****Increase
                (Decrease) in the Fair Value**
            **September
                30, 2006**
            
            **September
                30, 2006****of
                Commodity Derivative Contracts**
            **Non-Hedge**
            
            **Hedge**
            
            **Total**
            
            **Non-Hedge**
            
            **Hedge**
            
            **Total*****(In
                millions)*****Change
                in the Fair Value of****Commodity
                Derivative Contracts:**Outstanding
                net asset at beginning of period
            $
            12
            
            $
            -
            
            $
            12
            
            $
            27
            
            $
            -
            
            $
            27New
                contract
                value when entered
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Additions/change
                in value of existing contracts
            
            -
            
            
            -
            
            
            -
            
            
            2
            
            
            -
            
            
            2Change
                in
                techniques/assumptions
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Settled
                contracts
            
            -
            
            
            -
            
            
            -
            
            
            (3
            )
            
            -
            
            
            (3
            )Other
            
            -
            
            
            -
            
            
            -
            
            
            (14
            )
            
            -
            
            
            (14
            )**Net
                Assets - Derivative Contracts**
              **at
                End
                of Period****(1)**
            $
            12
            
            $
            -
            
            $
            12
            
            $
            12
            
            $
            -
            
            $
            12**Impact
                of Changes in Commodity Derivative Contracts****(2)**Income
                Statement effects (pre-tax)
            $
            -
            
            $
            -
            
            $
            -
            
            $
            (4
            )
            $
            -
            
            $
            (4
            )Balance
                Sheet
                effects:OCI
                (pre-tax)
            $
            -
            
            $
            -
            
            $
            -
            
            $
            -
            
            $
            -
            
            $
            -Regulatory
                liability
            $
            -
            
            $
            -
            
            $
            -
            
            $
            3
            
            $
            -
            
            $
            3


(1)  Includes
      $11 million
      in a non-hedge commodity derivative contract which is offset by a regulatory
      liability.


(2)  Represents
      the
      change in value of existing contracts, settled contracts and changes in
      techniques/assumptions.




Derivatives are included on the Consolidated Balance Sheet as of
      September 30, 2006 as follows:





**Balance
                Sheet Classification**
            
            **Non-Hedge**
            
            **Hedge**
            
            **Total*****(In
                millions)*****Non-Current-**Other
                deferred
                charges
            
            $
            12
            
            $
            -
            
            $
            12Other
                noncurrent liabilities
            
            
            -
            
            
            -
            
            
            -Net
                assets
            
            $
            12
            
            $
            -
            
            $
            12





The
      valuation of
      derivative contracts is based on observable market information to the extent
      that such information is available. In cases where such information is not
      available, Penelec relies on model-based information. The model provides
      estimates of future regional prices for electricity and an estimate of related
      price volatility. Penelec uses these results to develop estimates of fair value
      for financial reporting purposes and for internal management decision making.
      Sources of information for the valuation of commodity derivative contracts
      as of
      September 30, 2006 are summarized by year in the following table:





183











**Source
                of Information****Fair
                Value by Contract Year**
            
            **2006**(1)
            
            **2007**
            
            **2008**
            
            **2009**
            
            **2010**
            
            **Thereafter**
            
            **Total*****(In
                millions)***Other
                external
                sources(2)
                (3)
            
            $
            3
            
            $
            3
            
            $
            2
            
            $
            2
            
            $
            -
            
            $
            -
            
            $
            10Prices
                based
                on models(3)
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            2
            
            
            -
            
            
            2**Total**(3)
            
            **$**
            **3**
            
            **$**
            **3**
            
            **$**
            **2**
            
            **$**
            **2**
            
            **$**
            **2**
            
            **$**
            **-**
            
            **$**
            **12**





(1)  For
      the last quarter
      of 2006.


(2)  Broker
      quote
      sheets.


(3)  Includes
      $11 million
      from a non-hedge commodity derivative contract that is offset by a regulatory
      liability and does not affect earnings.





Penelec performs
      sensitivity
      analyses to estimate its exposure to the market risk of its commodity positions.
      A hypothetical 10% adverse shift in quoted market prices in the near term on
      both of Penelec's trading and non-trading derivative instruments would not
      have
      had a material effect on its consolidated financial position or cash flows
      as of
      September 30, 2006. Penelec estimates that if energy commodity prices
      experienced an adverse 10% change, net income for the next twelve months would
      not change, as the prices for all commodity positions are already above the
      contract price caps.





*Equity
      Price
      Risk*





Included
      in nuclear
      decommissioning trusts are marketable equity securities carried at their current
      fair value of approximately $68 million and $62 million as of
      September 30, 2006 and December 31, 2005, respectively. A hypothetical
      10% decrease in prices quoted by stock exchanges would result in a $7 million
      reduction in fair value as of September 30, 2006.





**Regulatory
      Matters**





Regulatory
      assets
      and liabilities are costs which have been authorized by the PPUC and the FERC
      for recovery from or credit to customers in future periods and, without such
      authorization, would have been charged or credited to income when incurred.
      Penelec’s net regulatory liabilities were approximately $127 million and
      $163 million as of September 30, 2006 and December 31, 2005,
      respectively, and are included under Noncurrent Liabilities on the Consolidated
      Balance Sheets.





A
      February 2002
      Commonwealth Court of Pennsylvania decision affirmed the June 2001 PPUC decision
      regarding approval of the FirstEnergy/GPU merger, remanded the issues of
      quantification and allocation of merger savings to the PPUC and denied Met-Ed
      and Penelec the rate relief initially approved in the PPUC decision. On October
      2, 2003, the PPUC issued an order concluding that the Commonwealth Court
      reversed the PPUC’s June 2001 order in its entirety. In accordance with the
      PPUC’s direction, Met-Ed and Penelec filed supplements to their tariffs that
      became effective in October 2003 and that reflected the CTC rates and shopping
      credits in effect prior to the June 2001 order. Met-Ed’s and Penelec’s combined
      portion of total net merger savings during 2001 - 2004 is estimated to be
      approximately $51 million. A procedural schedule was established by the ALJ
      on January 17, 2006 and the companies filed initial testimony on
      March 1, 2006. On May 4, 2006, the PPUC consolidated this proceeding
      with the April 10, 2006 comprehensive rate filing proceeding discussed
      below. Met-Ed and Penelec are unable to predict the outcome of this
      matter.





In
      an
      October 16, 2003 order, the PPUC approved September 30, 2004 as the
      date for Met-Ed's and Penelec's NUG trust fund refunds. The PPUC order also
      denied their accounting treatment request regarding the CTC rate/shopping credit
      swap by requiring Met-Ed and Penelec to treat the stipulated CTC rates that
      were
      in effect from January 1, 2002 on a retroactive basis. On October 22,
      2003, Met-Ed and Penelec filed an Objection with the Commonwealth Court asking
      that the Court reverse this PPUC finding; a Commonwealth Court judge
      subsequently denied their Objection on October 27, 2003 without
      explanation. On October 31, 2003, Met-Ed and Penelec filed an Application
      for Clarification of the Court order with the Commonwealth Court, a Petition
      for
      Review of the PPUC's October 2 and October 16, 2003 Orders, and an
      Application for Reargument, if the judge, in his clarification order, indicates
      that Met-Ed's and Penelec's Objection was intended to be denied on the merits.
      The Reargument Brief before the Commonwealth Court was filed on January 28,
      2005. Oral arguments were held on June 8, 2006. On July 19, 2006, the
      Commonwealth Court issued its decision affirming the PPUC’s prior orders.
      Although the decision denied the appeal of Met-Ed and Penelec, they had
      previously accounted for the treatment of costs required by the PPUC’s October
      2003 orders.





184








Met-Ed
      and Penelec
      purchase a portion of their PLR requirements from FES through a wholesale power
      sales agreement. Under this agreement, FES retains the supply obligation and
      the
      supply profit and loss risk for the portion of power supply requirements not
      self-supplied by Met-Ed and Penelec under their contracts with NUGs and other
      unaffiliated suppliers. The FES arrangement reduces Met-Ed's and Penelec's
      exposure to high wholesale power prices by providing power at a fixed price
      for
      their uncommitted PLR energy costs during the term of the agreement with FES.
      The wholesale power sales agreement with FES could automatically be extended
      for
      each successive calendar year unless any party elects to cancel the agreement
      by
      November 1 of the preceding year. On November 1, 2005, FES and the other
      parties thereto amended the agreement to provide FES the right in 2006 to
      terminate the agreement at any time upon 60 days notice. On April 7,
      2006, the parties to the wholesale power sales agreement entered into a Tolling
      Agreement that arises out of FES’ notice to Met-Ed and Penelec that FES elected
      to exercise its right to terminate the wholesale power sales agreement effective
      midnight December 31, 2006, because that agreement is not economically
      sustainable to FES.




In lieu of allowing such termination to become effective as of December 31,
      2006, the parties agreed, pursuant to the Tolling Agreement, to amend the
      wholesale power sales agreement to provide as follows:





1.  The
      termination
      provisions of the wholesale power sales agreement will be tolled for one year
      until December 31, 2007, provided that during such tolling
      period:





a.  FES
      will be
      permitted to terminate the wholesale power sales agreement at any time with
      sixty days written notice;


b.  Met-Ed
      and Penelec
      will procure through arrangements other than the wholesale power sales agreement
      beginning December 1, 2006 and ending December 31, 2007, approximately
      33% of the amounts of capacity and energy necessary to satisfy their PLR
      obligations for which Committed Resources (i.e., non-utility generation under
      contract to Met-Ed and Penelec, Met-Ed- and Penelec-owned generating facilities,
      purchased power contracts and distributed generation) have not been obtained;
      and


c.  FES
      will not be
      obligated to supply additional quantities of capacity and energy in the event
      that a supplier of Committed Resources defaults on its supply
      agreement.





2.  During
      the tolling
      period, FES will not act as an agent for Met-Ed or Penelec in procuring the
      services under 1.(b) above; and





3.  The
      pricing
      provision of the wholesale power sales agreement shall remain unchanged provided
      Met-Ed and Penelec comply with the provisions of the Tolling Agreement and
      any
      applicable provision of the wholesale power sales agreement.




In the event that FES elects not to terminate the wholesale power sales
      agreement effective midnight December 31, 2007, similar tolling agreements
      effective after December 31, 2007 are expected to be considered by FES for
      subsequent years if Penelec procures through arrangements other than the
      wholesale power sales agreement approximately 64%, 83% and 95% of the additional
      amounts of capacity and energy necessary to satisfy its PLR obligations for
      2008, 2009 and 2010, respectively, for which Committed Resources have not been
      obtained from the market. On September 26, 2006, Penelec successfully
      conducted a competitive RFP for 33% of its PLR obligation for which Committed
      Resources had not been obtained for the period December 1, 2006 through
      December 31, 2008.





The
      wholesale power
      sales agreement, as modified by the Tolling Agreement, requires Met-Ed and
      Penelec to satisfy the portion of their PLR obligations currently supplied
      by
      FES from unaffiliated suppliers at prevailing prices, which are likely to be
      higher than the current price charged by FES under the current agreement and,
      as
      a result, Met-Ed’s and Penelec’s purchased power costs could materially
      increase. If Met-Ed and Penelec were to replace the entire FES supply at current
      market power prices without corresponding regulatory authorization to increase
      their generation prices to customers, each company would likely incur a
      significant increase in operating expenses and experience a material
      deterioration in credit quality metrics. Under such a scenario, each company's
      credit profile would no longer be expected to support an investment grade rating
      for its fixed income securities. There can be no assurance, however, that if
      FES
      ultimately determines to terminate, further reduce, or significantly modify
      the
      agreement, timely regulatory relief will be granted by the PPUC pursuant to
      the
      April 10, 2006 comprehensive rate filing discussed below, or, to the extent
      granted, adequate to mitigate such adverse consequences.





185





Penelec
      made a
      comprehensive rate filing with the PPUC on April 10, 2006 that addresses a
      number of transmission, distribution and supply issues. If Penelec's preferred
      approach involving accounting deferrals is approved, the filing would increase
      annual revenues by $157 million. That filing includes, among other things,
      a request to charge customers for an increasing amount of market priced power
      procured through a CBP as the amount of supply provided under the existing
      FES
      agreement is phased out in accordance with the April 7, 2006 Tolling
      Agreement described above. Penelec
      also
      requested approval of the January 12, 2005 petition for the deferral of
      transmission-related costs discussed above, but only for those costs incurred
      during 2006. In this rate filing, Penelec also requested recovery of annual
      transmission and related costs incurred on or after January 1, 2007, plus
      the amortized portion of 2006 costs over a ten-year period, along with
      applicable carrying charges, through an adjustable rider similar to that
      implemented in Ohio. Changes in the
      recovery of NUG expenses are also included in the filing. The filing
      contemplates an increase in distribution rates for Penelec of $20 million
      annually. The PPUC suspended the effective date (June 10, 2006) of these
      rate changes for seven months after the filing as permitted under Pennsylvania
      law. If the PPUC adopts the overall positions taken in the intervenors’
testimony as filed, this would have a material adverse effect on the financial
      statements of FirstEnergy and Penelec. Hearings were held in late August 2006
      and all reply briefs were filed by October 6, 2006. The ALJ’s recommended
      decision is due by November 8, 2006 and the PPUC decision is expected by January
      12, 2007.





The
      annual goodwill
      impairment analysis performed in the third quarter of 2006 assumed management's
      best estimate of the rate increases that are expected to be granted in January
      2007 under Penelec’s comprehensive rate filing. If the PPUC authorizes less than
      the amounts assumed, an additional impairment analysis would be performed at
      that time and this could result in a future goodwill impairment loss that could
      be material. If rate relief were completely denied, it is estimated that
      approximately $374 million of Penelec’s goodwill would be impaired and
      written off. However, no adjustment to FirstEnergy’s goodwill on a consolidated
      basis would be recognized in that circumstance because the fair value of its
      regulated segment (which represents FirstEnergy's reporting unit to evaluate
      goodwill) would continue to exceed the carrying value of its investment in
      the
      segment.





As of September 30, 2006, Penelec's regulatory deferrals pursuant to the
      1998 Restructuring Settlement (including the Phase 2 Proceedings) and the
      FirstEnergy/GPU Merger Settlement Stipulation was $56 million. Penelec's
      $56 million is subject to the pending resolution of taxable income issues
      associated with NUG trust fund proceeds. The PPUC recently conducted a review
      and audit of a modification to the NUG purchased power stranded cost accounting
      methodology for Penelec. On August 18, 2006, a PPUC Order was entered requiring
      Penelec to reflect the deferred NUG cost balances as if the stranded cost
      accounting methodology modification had not been implemented. Penelec continues
      to believe that the stranded cost accounting methodology modification is
      appropriate and filed a petition with the PPUC pursuant to its Order for
      authorization to reflect the stranded cost accounting methodology modification
      effective January 1, 1999.





On
      January 12,
      2005, Met-Ed and Penelec filed, before the PPUC, a request for deferral of
      transmission-related costs beginning January 1, 2005. The OCA, OSBA, OTS,
      MEIUG, PICA, Allegheny Electric Cooperative and Pennsylvania Rural Electric
      Association all intervened in the case. Met-Ed and Penelec sought to consolidate
      this proceeding (and modified their request to provide deferral of 2006
      transmission-related costs only) with the comprehensive rate filing they made
      on
      April 10, 2006 as described above. On May 4, 2006, the PPUC approved
      the modified request. Accordingly, Penelec deferred approximately
      $21 million, representing transmission costs that were incurred from
      January 1, 2006 through September 30, 2006. On June 5, 2006, the OCA filed
      before the Commonwealth Court a petition for review of the PPUC’s approval of
      the deferral. On July 12, 2006, the Commonwealth Court granted the PPUC’s motion
      to quash the OCA’s appeal. The ratemaking treatment of the deferrals will be
      determined in the comprehensive rate filing proceeding
      discussed above.





On
      November 18,
      2004, the FERC issued an order eliminating the RTOR for transmission service
      between the MISO and PJM regions. The FERC also ordered the MISO, PJM and the
      transmission owners within MISO and PJM to submit compliance filings containing
      a SECA mechanism to recover lost RTOR revenues during a 16-month transition
      period from load serving entities. The FERC issued orders in 2005 setting the
      SECA for hearing. ATSI, JCP&L, Met-Ed, Penelec, and FES continue to be
      involved in the FERC hearings concerning the calculation and imposition of
      the
      SECA charges. The hearing was held in May 2006. Initial briefs were submitted
      on
      June 9, 2006, and reply briefs were filed on June 27, 2006. The Presiding Judge
      issued an Initial Decision on August 10, 2006, rejecting the compliance filings
      made by the RTOs and transmission owners, ruling on various issues and directing
      new compliance filings. This decision is subject to review and approval by
      the
      FERC. Briefs addressing the Initial Decision were filed on September 11, 2006
      and October 20, 2006. A final order could be issued by the FERC by the end
      of
      2006.





186








On
      January 31, 2005,
      certain PJM transmission owners made three filings with the FERC pursuant to
      a
      settlement agreement previously approved by the FERC. JCP&L, Met-Ed and
      Penelec were parties to that proceeding and joined in two of the filings. In
      the
      first filing, the settling transmission owners submitted a filing justifying
      continuation of their existing rate design within the PJM RTO. In the second
      filing, the settling transmission owners proposed a revised Schedule 12 to
      the
      PJM tariff designed to harmonize the rate treatment of new and existing
      transmission facilities. Interventions and protests were filed on February
      22,
      2005. In the third filing, Baltimore Gas and Electric Company and Pepco
      Holdings, Inc. requested a formula rate for transmission service provided within
      their respective zones. On May 31, 2005, the FERC issued an order on these
      cases. First, it set for hearing the existing rate design and indicated that
      it
      will issue a final order within six months. American Electric Power Company,
      Inc. filed in opposition proposing to create a "postage stamp" rate for high
      voltage transmission facilities across PJM. Second, the FERC approved the
      proposed Schedule 12 rate harmonization. Third, the FERC accepted the proposed
      formula rate, subject to refund and hearing procedures. On June 30, 2005, the
      settling PJM transmission owners filed a request for rehearing of the May 31,
      2005 order. On March 20, 2006, a settlement was filed with FERC in the formula
      rate proceeding that generally accepts the companies' formula rate proposal.
      The
      FERC issued an order approving this settlement on April 19, 2006. Hearings
      in
      the PJM rate design case concluded in April 2006. On July 13, 2006, an Initial
      Decision was issued by the ALJ. The ALJ adopted the Trial Staff’s position that
      the cost of all PJM transmission facilities should be recovered through a
      postage stamp rate. ****** The
      ALJ recommended
      an April 1, 2006 effective date for this change in rate design. If the FERC
      accepts this recommendation, the transmission rate applicable to many load
      zones
      in PJM would increase. FirstEnergy believes that significant additional
      transmission revenues would have to be recovered from the JCP&L, Met-Ed and
      Penelec transmission zones within PJM. JCP&L, Met-Ed and Penelec as part of
      the Responsible Pricing Alliance, filed a brief addressing the Initial Decision
      on August 14, 2006 and September 5, 2006. The case will be reviewed by the
      FERC
      with a decision anticipated in the fourth quarter of 2006. ******





See
      Note 11 to the
      consolidated financial statements for further details and a complete discussion
      of regulatory matters in Pennsylvania, including a more detailed discussion
      of
      reliability initiatives, including actions by the PPUC that impact
      Penelec.





**Environmental
      Matters** **





Penelec
      accrues
      environmental liabilities when it concludes that it is probable that it has
      an
      obligation for such costs and can reasonably determine the amount of such costs.
      Unasserted claims are reflected in Penelec's determination of environmental
      liabilities and are accrued in the period that they are both probable and
      reasonably estimable.





Penelec
      has been
      named a PRP at waste disposal sites, which may require cleanup under the
      Comprehensive Environmental Response, Compensation and Liability Act of 1980.
      Allegations of disposal of hazardous substances at historical sites and the
      liability involved are often unsubstantiated and subject to dispute; however,
      federal law provides that all PRPs for a particular site are liable on a joint
      and several basis. Therefore, environmental liabilities that are considered
      probable have been recognized on the Consolidated Balance Sheet as of September
      30, 2006, based on estimates of the total costs of cleanup, Penelec’s
      proportionate responsibility for such costs and the financial ability of other
      unaffiliated entities to pay.





**Other
      Legal Proceedings**





There
      are various
      lawsuits, claims (including claims for asbestos exposure) and proceedings
      related to Penelec’s normal business operations pending against Penelec. The
      other material items not otherwise discussed below are described in
      Note 10(C) to the consolidated financial statements.





187





*Power
      Outages
      and Related Litigation*




On August 14, 2003, various states and parts of southern Canada experienced
      widespread power outages. The outages affected approximately 1.4 million
      customers in FirstEnergy's service area. The U.S. - Canada Power System Outage
      Task Force’s final report in April 2004 on the outages concluded, among other
      things, that the problems leading to the outages began in FirstEnergy’s Ohio
      service area. Specifically,
      the
      final report concluded, among other things, that the initiation of the
      August 14, 2003 power outages resulted from an alleged failure of both
      FirstEnergy and ECAR to assess and understand perceived inadequacies within
      the
      FirstEnergy system; inadequate situational awareness of the developing
      conditions; and a perceived failure to adequately manage tree growth in certain
      transmission rights of way. The Task Force also concluded that there was a
      failure of the interconnected grid's reliability organizations (MISO and PJM)
      to
      provide effective real-time diagnostic support. The final report is publicly
      available through the Department of Energy’s Web site (www.doe.gov). FirstEnergy
      believes that the final report does not provide a complete and comprehensive
      picture of the conditions that contributed to the August 14, 2003 power
      outages and that it does not adequately address the underlying causes of the
      outages. FirstEnergy remains convinced that the outages cannot be explained
      by
      events on any one utility's system. The final report contained 46
“recommendations to prevent or minimize the scope of future blackouts.”
Forty-five of those recommendations related to broad industry or policy matters
      while one, including subparts, related to activities the Task Force recommended
      be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct
      the
      causes of the August 14, 2003 power outages. FirstEnergy implemented
      several initiatives, both prior to and since the August 14, 2003 power
      outages, which were independently verified by NERC as complete in 2004 and
      were
      consistent with these and other recommendations and collectively enhance the
      reliability of its electric system. FirstEnergy’s implementation of these
      recommendations in 2004 included completion of the Task Force recommendations
      that were directed toward FirstEnergy. FirstEnergy is also proceeding with
      the
      implementation of the recommendations that were to be completed subsequent
      to
      2004 and will continue to periodically assess the FERC-ordered Reliability
      Study
      recommendations for forecasted 2009 system conditions, recognizing revised
      load
      forecasts and other changing system conditions which may impact the
      recommendations. Thus far, implementation of the recommendations has not
      required, nor is expected to require, substantial investment in new or material
      upgrades to existing equipment. The FERC or other applicable government agencies
      and reliability coordinators may, however, take a different view as to
      recommended enhancements or may recommend additional enhancements in the future
      as a result of adoption of mandatory reliability standards pursuant to the
      EPACT
      that could require additional material expenditures.





FirstEnergy
      is
      vigorously defending these actions, but cannot predict the outcome of any of
      these proceedings or whether any further regulatory proceedings or legal actions
      may be initiated against the Companies. In particular, if FirstEnergy or its
      subsidiaries were ultimately determined to have legal liability in connection
      with these proceedings, it could have a material adverse effect on FirstEnergy's
      or its subsidiaries' financial condition, results of operations and cash
      flows.





**New
      Accounting Standards and Interpretations**





*SAB
                108 -
                “Considering the Effects of Prior Year Misstatements when Quantifying
                Misstatements in Current Year Financial
                Statements”*





In September 2006, the SEC issued SAB 108, which provides interpretive guidance
      on how registrants should quantify financial statement misstatements. There
      is
      currently diversity in practice, with the two commonly used methods to quantify
      misstatements being the “rollover” method (which primarily focuses on the income
      statement impact of misstatements) and the “iron curtain” method (which focuses
      on the balance sheet impact). SAB 108 requires registrants to use a dual
      approach whereby both of these methods are considered in evaluating the
      materiality of financial statement errors. Prior materiality assessments will
      need to be reconsidered using both the rollover and iron curtain methods. This
      guidance will be effective for Penelec in the fourth quarter of 2006. Penelec does
      not expect this Statement to have a material impact on its financial
      statements.





*SFAS
      157 - “Fair
      Value Measurements”*





In September 2006, the FASB issued SFAS 157, that establishes how companies
      should measure fair value when they are required to use a fair value measure
      for
      recognition or disclosure purposes under GAAP. This Statement addresses the
      need
      for increased consistency and comparability in fair value measurements and
      for
      expanded disclosures about fair value measurements. The key changes to current
      practice are: (1) the definition of fair value which focuses on an exit price
      rather than entry price; (2) the methods used to measure fair value such as
      emphasis that fair value is a market-based measurement, not an entity-specific
      measurement, as well as the inclusion of an adjustment for risk, restrictions
      and credit standing; and (3) the expanded disclosures about fair value
      measurements.





188





This Statement is effective for financial statements issued for fiscal years
      beginning after November 15, 2007, and interim periods within those years.
      Penelec is currently evaluating the impact of this Statement on its financial
      statements.





*SFAS
                158 -
                “Employers’ Accounting for Defined Benefit Pension and Other
                Postretirement Plans-an amendment of FASB Statements No. 87, 88,
                106, and
                132(R)”*





In September 2006, the FASB issued SFAS 158, which requires companies to
      recognize a net liability or asset to report the overfunded or underfunded
      status of their defined benefit pension and other postretirement benefit plans
      on their balance sheets and recognize changes in funded status in the year
      in
      which the changes occur through other comprehensive income. The funded status
      to
      be measured is the difference between plan assets at fair value and the benefit
      obligation. This Statement requires that gains and losses and prior service
      costs or credits, net of tax, that arise during the period be recognized as
      a
      component of other comprehensive income and not as components of net periodic
      benefit cost. Additional information should also be disclosed in the notes
      to
      the financial statements about certain effects on net periodic benefit cost
      for
      the next fiscal year that arise from delayed recognition of the gains or losses,
      prior service costs or credits, and transition asset or obligation. Upon the
      initial application of this Statement and subsequently, an employer should
      continue to apply the provisions in Statements 87, 88 and 106 in measuring
      plan
      assets and benefit obligations as of the date of its statement of financial
      position and in determining the amount of net periodic benefit cost. This
      Statement is effective for Penelec as of December 31, 2006. Penelec is
      currently evaluating the impact of this Statement on its financial
      statements.





*FSP
      FIN 46(R)-6
      - “Determining the Variability to Be Considered in Applying FASB interpretation
      No. 46(R)”*





In
      April 2006, the
      FASB issued FSP FIN 46(R)-6 that addresses how a reporting enterprise should
      determine the variability to be considered in applying FASB interpretation
      No.
      46 (revised December 2003). Penelec adopted FIN 46(R) in the first quarter
      of
      2004, consolidating VIE’s when Penelec or one of its subsidiaries is determined
      to be the VIE’s primary beneficiary. The variability that is considered in
      applying interpretation 46(R) affects the determination of (a) whether the
      entity is a VIE; (b) which interests are variable interests in the entity;
      and
      (c) which party, if any, is the primary beneficiary of the VIE. This FSP states
      that the variability to be considered shall be based on an analysis of the
      design of the entity, involving two steps:





Step
                1:
            Analyze
                the
                nature of the risks in the entityStep
                2:
            Determine
                the
                purpose(s) for which the entity was created and determine the variability
                the entity is designed to create and pass along to its interest
                holders.





After
      determining
      the variability to consider, the reporting enterprise can determine which
      interests are designed to absorb that variability. The guidance in this FSP
      is
      applied prospectively to all entities (including newly created entities) with
      which that enterprise first becomes involved and to all entities previously
      required to be analyzed under interpretation 46(R) when a reconsideration event
      has occurred after July 1, 2006. Penelec does not expect this Statement to
      have a material impact on its financial statements.





*FIN
      48 -
“Accounting for Uncertainty in Income Taxes - an interpretation of FASB
      Statement No. 109.”*





In
      June 2006, the
      FASB issued FIN 48 which clarifies the accounting for uncertainty in income
      taxes recognized in an enterprise’s financial statements in accordance with FASB
      Statement No. 109, “Accounting for Income Taxes.” This interpretation prescribes
      a recognition threshold and measurement attribute for the financial statement
      recognition and measurement of a tax position taken or expected to be taken
      on a
      tax return. This interpretation also provides guidance on derecognition,
      classification, interest, penalties, accounting in interim periods, disclosure
      and transition. The evaluation of a tax position in accordance with this
      interpretation will be a two-step process. The first step will determine if
      it
      is more likely than not that a tax position will be sustained upon examination
      and should therefore be recognized. The second step will measure a tax position
      that meets the more likely than not recognition threshold to determine the
      amount of benefit to recognize in the financial statements. This interpretation
      is effective for fiscal years beginning after December 15, 2006. Penelec is
      currently evaluating the impact of this Statement.








189







**ITEM
        3.
        QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
        RISK**
 
 See
“Management’s
        Discussion and Analysis of Results of Operation and Financial Condition -
        Market
        Risk Information” in Item 2 above.




**ITEM
      4.
      CONTROLS AND PROCEDURES**





**(a)**  **EVALUATION
      OF DISCLOSURE CONTROLS AND PROCEDURES**





The
      applicable
      registrant's chief executive officer and chief financial officer have reviewed
      and evaluated the registrant's disclosure controls and procedures. The term
      disclosure controls and procedures means controls and other procedures of a
      registrant that are designed to ensure that information required to be disclosed
      by the registrant in the reports that it files or submits under the Securities
      Exchange Act of 1934 (15 U.S.C. 78a et seq.) is recorded, processed, summarized
      and reported, within the time periods specified in the Securities and Exchange
      Commission's rules and forms. Disclosure controls and procedures include,
      without limitation, controls and procedures designed to ensure that information
      required to be disclosed by an issuer in the reports that it files or submits
      under that Act is accumulated and communicated to the registrant's management,
      including its principal executive and principal financial officers, or persons
      performing similar functions, as appropriate to allow timely decisions regarding
      required disclosure. Based on that evaluation, those officers have concluded
      that the applicable registrant's disclosure controls and procedures are
      effective and were designed to bring to their attention material information
      relating to the registrant and its consolidated subsidiaries by others within
      those entities.





**(b)**  **CHANGES
      IN
      INTERNAL CONTROLS**


During
        the quarter
        ended September 30, 2006, t he
        registrants
        modified the internal controls over the preparation and review of their
        Consolidated Statements of Cash Flows. There
        were no other
        changes in the registrants' internal control over financial reporting that
        have
        materially affected, or are reasonably likely to materially affect, the
        registrants' internal control over financial reporting.




190





***PART
      II. OTHER INFORMATION***





**ITEM
      1.**  **LEGAL
      PROCEEDINGS**





Information
      required
      for Part II, Item 1 is incorporated by reference to the discussions in Notes
      10
      and 11 of the Consolidated Financial Statements in Part I, Item 1 of this Form
      10-Q.


**ITEM
      1A.**  **RISK
      FACTORS**





See
      Item 1A RISK
      FACTORS in Part I of the Form 10-K for the year ended December 31, 2005 for
      a discussion of the risk factors of FirstEnergy and the subsidiary registrants.
      For the quarter ended September 30, 2006, there have been no material
      changes to these risk factors.





**ITEM
      2.**  **UNREGISTERED
      SALES OF EQUITY SECURITIES AND USE OF PROCEEDS**





**(c)**  **FirstEnergy**





The
      table below
      includes information on a monthly basis regarding purchases made by FirstEnergy
      of its common stock.





**Period****July
                1-31,**
            
            **August
                1-31,**
            
            **September
                1-30,**
            
            **Third****2006**
            
            **2006**
            
            **2006**
            
            **Quarter**Total
                Number
                of Shares Purchased(a)
            
            203,030
            
            10,872,244
            
            265,207
            
            11,340,481Average
                Price
                Paid per Share
            
            $55.33
            
            $56.44
            
            $56.42
            
            $56.42Total
                Number
                of Shares PurchasedAs
                Part of
                Publicly Announced Plansor
                Programs(b)
            
            --
            
            10,630,759
            
            --
            
            10,630,759Maximum
                Number
                (or Approximate DollarValue)
                of
                Shares that May Yet BePurchased
                Under the Plans or Programs
            
            12,000,000
            
            1,369,241
            
            1,369,241
            
            1,369,241





(a)
            Share
                amounts
                reflect purchases on the open market to satisfy FirstEnergy's obligations
                to deliver common stock under its Executive and Director Incentive
                Compensation Plan, Deferred Compensation Plan for Outside Directors,
                Executive Deferred Compensation Plan, Savings Plan and Stock Investment
                Plan. In addition, such amounts reflect shares tendered by employees
                to
                pay the exercise price or withholding taxes upon exercise of stock
                options
                granted under the Executive and Director Incentive Compensation Plan
                and
                shares purchased as part of publicly announced plans.(b)
            FirstEnergy
                publicly announced, on June 20, 2006, a plan to repurchase up to
                12 million shares of its common
                stock.








191





**ITEM
      6.**  **EXHIBITS**





**Exhibit
                Number****FirstEnergy**10.1
                *
            Confirmation
                dated August 9, 2006 between FirstEnergy Corp and JP Morgan Chase
                Bank
                National Association10.2
            $2,750,000,000
                Credit Agreement, dated as of August 24, 2006 among FirstEnergy Corp.,
                FirstEnergy Solutions Corp., American Transmission Systems, Inc.,
                Ohio
                Edison Company, Pennsylvania Power Company, The Cleveland Electric
                Illuminating Company, The Toledo Edison Company, Jersey Central Power
                & Light Company, Metropolitan Edison Company and Pennsylvania Electric
                Company, as Borrowers, the banks party thereto, the fronting banks
                party
                thereto and the swing line lenders party thereto (incorporated by
                reference to Exhibit 10.1 to Registrant’s Form 8-K filed on August 24,
                2006)12
            Fixed
                charge
                ratios15
            Letter
                from
                independent registered public accounting firm31.1
            Certification
                of chief executive officer, as adopted pursuant to Rule
                13a-15(e)/15d-(e).31.2
            Certification
                of chief financial officer, as adopted pursuant to Rule
                13a-15(e)/15d-(e).32
            Certification
                of chief executive officer and chief financial officer, pursuant
                to 18
                U.S.C. Section 1350.**OE**10.1
            $2,750,000,000
                Credit Agreement, dated as of August 24, 2006 among FirstEnergy Corp.,
                FirstEnergy Solutions Corp., American Transmission Systems, Inc.,
                Ohio
                Edison Company, Pennsylvania Power Company, The Cleveland Electric
                Illuminating Company, The Toledo Edison Company, Jersey Central Power
                & Light Company, Metropolitan Edison Company and Pennsylvania Electric
                Company, as Borrowers, the banks party thereto, the fronting banks
                party
                thereto and the swing line lenders party thereto (incorporated by
                reference to Exhibit 10.1 to Registrant’s Form 8-K filed on August 24,
                2006)12
            Fixed
                charge
                ratios15
            Letter
                from
                independent registered public accounting firm31.1
            Certification
                of chief executive officer, as adopted pursuant to Rule
                13a-15(e)/15d-(e).31.2
            Certification
                of chief financial officer, as adopted pursuant to Rule
                13a-15(e)/15d-(e).32
            Certification
                of chief executive officer and chief financial officer, pursuant
                to 18
                U.S.C. Section 1350.**Penn**10.1
            $2,750,000,000
                Credit Agreement, dated as of August 24, 2006 among FirstEnergy Corp.,
                FirstEnergy Solutions Corp., American Transmission Systems, Inc.,
                Ohio
                Edison Company, Pennsylvania Power Company, The Cleveland Electric
                Illuminating Company, The Toledo Edison Company, Jersey Central Power
                & Light Company, Metropolitan Edison Company and Pennsylvania Electric
                Company, as Borrowers, the banks party thereto, the fronting banks
                party
                thereto and the swing line lenders party thereto (incorporated by
                reference to Exhibit 10.1 to Registrant’s Form 8-K filed on August 24,
                2006)15
            Letter
                from
                independent registered public accounting firm31.1
            Certification
                of chief executive officer, as adopted pursuant to Rule
                13a-15(e)/15d-(e).31.2
            Certification
                of chief financial officer, as adopted pursuant to Rule
                13a-15(e)/15d-(e).32
            Certification
                of chief executive officer and chief financial officer, pursuant
                to 18
                U.S.C. Section 1350.**CEI**10.1
            $2,750,000,000
                Credit Agreement, dated as of August 24, 2006 among FirstEnergy Corp.,
                FirstEnergy Solutions Corp., American Transmission Systems, Inc.,
                Ohio
                Edison Company, Pennsylvania Power Company, The Cleveland Electric
                Illuminating Company, The Toledo Edison Company, Jersey Central Power
                & Light Company, Metropolitan Edison Company and Pennsylvania Electric
                Company, as Borrowers, the banks party thereto, the fronting banks
                party
                thereto and the swing line lenders party thereto (incorporated by
                reference to Exhibit 10.1 to Registrant’s Form 8-K filed on August 24,
                2006)12
            Fixed
                charge
                ratios15
            Letter
                from
                independent registered public accounting firm31.1
            Certification
                of chief executive officer, as adopted pursuant to Rule
                13a-15(e)/15d-(e).31.2
            Certification
                of chief financial officer, as adopted pursuant to Rule
                13a-15(e)/15d-(e).32
            Certification
                of chief executive officer and chief financial officer, pursuant
                to 18
                U.S.C. Section 1350.**TE**10.1
            $2,750,000,000
                Credit Agreement, dated as of August 24, 2006 among FirstEnergy Corp.,
                FirstEnergy Solutions Corp., American Transmission Systems, Inc.,
                Ohio
                Edison Company, Pennsylvania Power Company, The Cleveland Electric
                Illuminating Company, The Toledo Edison Company, Jersey Central Power
                & Light Company, Metropolitan Edison Company and Pennsylvania Electric
                Company, as Borrowers, the banks party thereto, the fronting banks
                party
                thereto and the swing line lenders party thereto (incorporated by
                reference to Exhibit 10.1 to Registrant’s Form 8-K filed on August 24,
                2006)12
            Fixed
                charge
                ratios15
            Letter
                from
                independent registered public accounting firm31.1
            Certification
                of chief executive officer, as adopted pursuant to Rule
                13a-15(e)/15d-(e).31.2
            Certification
                of chief financial officer, as adopted pursuant to Rule
                13a-15(e)/15d-(e).32
            Certification
                of chief executive officer and chief financial officer, pursuant
                to 18
                U.S.C. Section 1350.





192








**JCP&L**4.1
            Indenture
                dated as of August 10, 2006 between JCP&L Transition Funding II LLC as
                Issuer and The Bank of New York as Trustee (incorporated by reference
                to
                Exhibit 4.1 of JCP&L's Form 8-K filed on August 10,
                2006)4.2
            2006-A
                Series
                Supplement dated as of August 10, 2006 between JCP&L Transition
                Funding II LLC as Issuer and The Bank of New York as Trustee (incorporated
                by reference to Exhibit 4.2 of JCP&L's Form 8-K filed on August 10,
                2006)4.3
            Form
                of
                Transition Bond (incorporated by reference to Exhibit 4.2 of JCP&L's
                Form 8-K filed on August 10, 2006)10.1
            Bondable
                Transition Property Sale Agreement dated as of August 10, 2006 between
                JCP&L Transition Funding II LLC as Issuer and Jersey Central Power
                & Light Company as Seller (incorporated by reference to Exhibit 10.1
                of JCP&L's Form 8-K filed on August 10, 2006)10.2
            Bondable
                Transition Property Service Agreement dated as of August 10, 2006
                between
                JCP&L Transition Funding II LLC as Issuer and Jersey Central Power
                & Light Company as Servicer (incorporated by reference to Exhibit 10.2
                of JCP&L's Form 8-K filed on August 10, 2006)10.3
            Administration
                Agreement dated as of August 10, 2006 between JCP&L Transition Funding
                II LLC as Issuer and FirstEnergy Service Company as Administrator
                (incorporated by reference to Exhibit 10.3 of JCP&L's Form 8-K filed
                on August 10, 2006)10.4
            $2,750,000,000
                Credit Agreement, dated as of August 24, 2006 among FirstEnergy Corp.,
                FirstEnergy Solutions Corp., American Transmission Systems, Inc.,
                Ohio
                Edison Company, Pennsylvania Power Company, The Cleveland Electric
                Illuminating Company, The Toledo Edison Company, Jersey Central Power
                & Light Company, Metropolitan Edison Company and Pennsylvania Electric
                Company, as Borrowers, the banks party thereto, the fronting banks
                party
                thereto and the swing line lenders party thereto (incorporated by
                reference to Exhibit 10.1 to Registrant’s Form 8-K filed on August 24,
                2006)12
            Fixed
                charge
                ratios15
            Letter
                from
                independent registered public accounting firm31.1
            Certification
                of chief financial officer, as adopted pursuant to Rule
                13a-15(e)/15d-(e).31.2
            Certification
                of chief executive officer, as adopted pursuant to Rule
                13a-15(e)/15d-(e).32
            Certification
                of chief executive officer and chief financial officer, pursuant
                to 18
                U.S.C. Section 1350.**Met-Ed**10.1
            $2,750,000,000
                Credit Agreement, dated as of August 24, 2006 among FirstEnergy Corp.,
                FirstEnergy Solutions Corp., American Transmission Systems, Inc.,
                Ohio
                Edison Company, Pennsylvania Power Company, The Cleveland Electric
                Illuminating Company, The Toledo Edison Company, Jersey Central Power
                & Light Company, Metropolitan Edison Company and Pennsylvania Electric
                Company, as Borrowers, the banks party thereto, the fronting banks
                party
                thereto and the swing line lenders party thereto (incorporated by
                reference to Exhibit 10.1 to Registrant’s Form 8-K filed on August 24,
                2006)12
            Fixed
                charge
                ratios31.1
            Certification
                of chief executive officer, as adopted pursuant to Rule
                13a-15(e)/15d-(e).31.2
            Certification
                of chief financial officer, as adopted pursuant to Rule
                13a-15(e)/15d-(e).32
            Certification
                of chief executive officer and chief financial officer, pursuant
                to 18
                U.S.C. Section 1350.**Penelec**10.1
            $2,750,000,000
                Credit Agreement, dated as of August 24, 2006 among FirstEnergy Corp.,
                FirstEnergy Solutions Corp., American Transmission Systems, Inc.,
                Ohio
                Edison Company, Pennsylvania Power Company, The Cleveland Electric
                Illuminating Company, The Toledo Edison Company, Jersey Central Power
                & Light Company, Metropolitan Edison Company and Pennsylvania Electric
                Company, as Borrowers, the banks party thereto, the fronting banks
                party
                thereto and the swing line lenders party thereto (incorporated by
                reference to Exhibit 10.1 to Registrant’s Form 8-K filed on August 24,
                2006)12
            Fixed
                charge
                ratios15
            Letter
                from
                independent registered public accounting firm31.1
            Certification
                of chief executive officer, as adopted pursuant to Rule
                13a-15(e)/15d-(e).31.2
            Certification
                of chief financial officer, as adopted pursuant to Rule
                13a-15(e)/15d-(e).32
            Certification
                of chief executive officer and chief financial officer, pursuant
                to 18
                U.S.C. Section 1350.




*
        Confidential
        treatment has been requested for certain portions of the Exhibit. Omitted
        portions have been filed separately with the SEC.


Pursuant to reporting requirements of respective financings, FirstEnergy, OE,
      CEI, TE, JCP&L, Met-Ed and Penelec are required to file fixed charge ratios
      as an exhibit to this Form 10-Q. Penn does not have similar financing reporting
      requirements and has not filed its respective fixed charge ratios.





Pursuant
      to
      paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, neither FirstEnergy,
      OE,
      CEI, TE, Penn, JCP&L, Met-Ed nor Penelec have filed as an exhibit to this
      Form 10-Q any instrument with respect to long-term debt if the respective
      total amount of securities authorized thereunder does not exceed 10% of its
      consolidated total assets, but each hereby agrees to furnish to the SEC on
      request any such documents.





193





**SIGNATURE**











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








November
      1,
      2006

















**FIRSTENERGY
                CORP.**Registrant**OHIO
                EDISON COMPANY**Registrant**THE
                CLEVELAND ELECTRIC****ILLUMINATING
                COMPANY**Registrant**THE
                TOLEDO EDISON COMPANY**Registrant**PENNSYLVANIA
                POWER COMPANY**Registrant**JERSEY
                CENTRAL POWER & LIGHT COMPANY**Registrant**METROPOLITAN
                EDISON COMPANY**Registrant**PENNSYLVANIA
                ELECTRIC COMPANY**Registrant

















/s/Harvey
                L.
                WagnerHarvey
                L.
                WagnerVice
                President, Controllerand
                Chief
                Accounting Officer








194