**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, 2005**





**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 each registrant is an accelerated filer (as defined in Rule
        12b-2
        of the Act):
 
 YesX
              No
              FirstEnergy
                  Corp.Yes
              NoX
              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
 
 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
                NOVEMBER 2****,
                2005**FirstEnergy
                Corp., $.10 par value
            329,836,276Ohio
                Edison
                Company, no par value
            100The
                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, Pennsylvania
        Power Company, The Cleveland Electric Illuminating Company, The Toledo Edison
        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 our regulated utilities to collect transition and other charges,
        maintenance costs being higher than anticipated, legislative and regulatory
        changes (including revised environmental requirements), the uncertainty of
        the
        timing and amounts of the capital expenditures (including that such amounts
        could be higher than anticipated) or levels of emission reductions related
        to
        the settlement agreement 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 government investigations and oversight,
        including by the Securities and Exchange Commission, the United States
        Attorney’s Office and the Nuclear Regulatory Commission 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 availability and cost
        of
        capital, rising interest rates and other inflationary trends, 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 of strategic goals (including the proposed transfer
        of nuclear generation assets), the ability to improve electric commodity
        margins
        and to experience growth in the distribution business, any decision of the
        Pennsylvania Public Utility Commission regarding the plan filed by Penn on
        October 11, 2005 to secure electricity supply for its customers at a set
        rate,
        the ability to access the public securities and other capital markets, the
        outcome, cost and other effects of present and potential legal and
        administrative proceedings and claims related to the August 14, 2003
        regional power outage, the final outcome in the proceeding related to
        FirstEnergy's Application for a Rate Stabilization Plan (RSP) in Ohio,
        specifically, the PUCO's acceptance of the September 9, 2005 proposed
        supplement to the RSP, 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, 2004, 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. Dividends declared
        from time to time on FirstEnergy's common stock during any annual period
        may in
        aggregate vary from the indicated amounts due to circumstances considered
        by
        FirstEnergy's Board of Directors at the time of the actual declarations.
        The
        registrants expressly disclaim any current intention to update any
        forward-looking statements contained in this document 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**
                **Results of Operation and Financial Condition**Notes
                  to
                  Consolidated Financial Statements
              1-25**FirstEnergy
                  Corp.**Consolidated
                  Statements of Income
              26Consolidated
                  Statements of Comprehensive Income
              27Consolidated
                  Balance Sheets
              28Consolidated
                  Statements of Cash Flows
              29Report
                  of
                  Independent Registered Public Accounting Firm
              30Management's
                  Discussion and Analysis of Results of Operations and
              31-65Financial
                  Condition**Ohio
                  Edison Company**Consolidated
                  Statements of Income and Comprehensive Income
              66Consolidated
                  Balance Sheets
              67Consolidated
                  Statements of Cash Flows
              68Report
                  of
                  Independent Registered Public Accounting Firm
              69Management's
                  Discussion and Analysis of Results of Operations and
              70-82Financial
                  Condition**The
                  Cleveland Electric Illuminating Company**Consolidated
                  Statements of Income and Comprehensive Income
              83Consolidated
                  Balance Sheets
              84Consolidated
                  Statements of Cash Flows
              85Report
                  of
                  Independent Registered Public Accounting Firm
              86Management's
                  Discussion and Analysis of Results of Operations and
              87-98Financial
                  Condition**The
                  Toledo Edison Company**Consolidated
                  Statements of Income and Comprehensive Income
              99Consolidated
                  Balance Sheets
              100Consolidated
                  Statements of Cash Flows
              101Report
                  of
                  Independent Registered Public Accounting Firm
              102Management's
                  Discussion and Analysis of Results of Operations and
              103-114Financial
                  Condition**Pennsylvania
                  Power Company**ConsolidatedStatements
                  of Income and Comprehensive Income
              115ConsolidatedBalance
                  Sheets
              116ConsolidatedStatements
                  of Cash Flows
              117Report
                  of
                  Independent Registered Public Accounting Firm
              118Management's
                  Discussion and Analysis of Results of Operations and
              119-127Financial
                  Condition
 
 
  i
   **TABLE
        OF
        CONTENTS (Cont'd)**
 
 
 **Pages****Jersey
                  Central Power & Light Company**Consolidated
                  Statements of Income and Comprehensive Income
              128Consolidated
                  Balance Sheets
              129Consolidated
                  Statements of Cash Flows
              130Report
                  of
                  Independent Registered Public Accounting Firm
              131Management's
                  Discussion and Analysis of Results of Operations and
              132-140Financial
                  Condition**Metropolitan
                  Edison Company**Consolidated
                  Statements of Income and Comprehensive Income
              141Consolidated
                  Balance Sheets
              142Consolidated
                  Statements of Cash Flows
              143Report
                  of
                  Independent Registered Public Accounting Firm
              144Management's
                  Discussion and Analysis of Results of Operations and
              145-153Financial
                  Condition**Pennsylvania
                  Electric Company**Consolidated
                  Statements of Income and Comprehensive Income
              154Consolidated
                  Balance Sheets
              155Consolidated
                  Statements of Cash Flows
              156Report
                  of
                  Independent Registered Public Accounting Firm
              157Management's
                  Discussion and Analysis of Results of Operations and
              158-166Financial
                  Condition**Item
                  3.****Quantitative
                  and Qualitative Disclosures About Market Risk**
              167**Item
                  4.****Controls
                  and Procedures**
              167**Part
                  II.****Other
                  Information****Item
                  1.****Legal
                  Proceedings**
              168168**Item
                  2.****Changes
                  in Securities, Use of Proceeds and Issuer Purchases of Equity
                  Securities****Item
                5.  Other
                Information**
              168**Item 6.****Exhibits**
              169-184
 
 
  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, Incorporated, owns and operates transmission
                      facilitiesCEI
                  The
                      Cleveland
                      Electric Illuminating Company, an Ohio electric utility operating
                      subsidiaryCFC
                  Centerior
                      Funding Corporation, a wholly owned finance subsidiary of
                      CEICompanies
                  OE,
                      CEI, TE,
                      Penn, JCP&L, Met-Ed and PenelecEUOC
                  Electric
                      Utility Operating Companies (OE, CEI, TE, Penn, JCP&L, Met-Ed,
                      Penelec, and ATSI)FENOC
                  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 registered 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 onNovember 7,
                      2001JCP&L
                  Jersey
                      Central Power & Light Company, a New Jersey electric utility operating
                      subsidiaryJCP&L
                      Transition
                  JCP&L
                      Transition Funding LLC, a Delaware limited liability company
                      and issuer of
                      transitionbondsMet-Ed
                  Metropolitan
                      Edison Company, a Pennsylvania electric utility operating
                      subsidiaryMYR
                  MYR
                      Group,
                      Inc., a utility infrastructure construction service
                      companyNGC
                  FirstEnergy
                      Nuclear Generation Corp. established to acquire FirstEnergy's
                      nuclear
                      generatingfacilitiesOE
                  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
                      Publicos
  
 The
          following
          abbreviations and acronyms are used to identify frequently used terms in
          this
          report:
 
 AOCL
                  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”ARO
                  Asset
                      Retirement ObligationBGS
                  Basic
                      Generation ServiceCAIR
                  Clean
                      Air
                      Interstate RuleCAL
                  Confirmatory
                      Action LetterCAT
                  Commercial
                      Activity TaxCO2
                  Carbon
                    DioxideCTC
                  Competitive
                      Transition ChargeDOJ
                  United
                      States
                      Department of JusticeECAR
                  East
                      Central
                      Area Reliability Coordination AgreementEITF
                  Emerging
                      Issues Task ForceEITF
                      03-1
                  EITF
                      Issue
                      No. 03-1, "The Meaning of Other-Than-Temporary and Its Application
                      to
                      CertainInvestments”EITF
                      04-13
                  EITF
                      Issue
                      No. 04-13, “Accounting for Purchases and Sales of Inventory with the SameCounterparty”EITF
                      99-19
                  EITF
                      Issue
                      No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an
                      Agent”EPA
                  Environmental
                      Protection AgencyERO
                  Electric
                      Reliability OrganizationFASB
                  Financial
                      Accounting Standards BoardFERC
                  Federal
                      Energy Regulatory CommissionFIN
                  FASB
                      InterpretationFIN
                      46R
                  FIN
                      46
                      (revised December 2003), "Consolidation of Variable Interest
                      Entities"
  iii
  FIN
                      47
                  FASB
                      Interpretation 47, “Accounting for Conditional Asset Retirement
                      Obligations - aninterpretation
                      of FASB Statement No. 143”FMBs
                  First
                      Mortgage BondsFSP
                  FASB
                      Staff
                      PositionFSP
                      EITF
                      03-1-1
                  FASB
                      Staff
                      Position No. EITF Issue 03-1-1, "Effective Date of Paragraphs
                      10-20 of
                      EITF IssueNo.
                      03-1,*The
                      Meaning of Other-Than-Temporary Impairment and Its Application
                      to Certain**Investments"*FSP
                      109-1
                  FASB
                      Staff
                      Position No. 109-1, “Application of FASB Statement No. 109*,
                      Accounting for Income*
                    *Taxes*,
                      to the Tax
                      Deduction on Qualified Production Activities Provided by the
                      American
                      Jobs
                    Creation
                      Act
                      of 2004”GCAF
                  Generation
                      Charge Adjustment FactorGAAP
                  Accounting
                      Principles Generally Accepted in the United StatesGHG
                  Greenhouse
                      GasesHVAC
                  Heating,
                      Ventilation and Air-conditioningIBEW
                  International
                      Brotherhood of Electrical WorkersKWH
                  Kilowatt-hoursLOC
                  Letter
                      of
                      CreditMEIUG
                  Met-Ed
                      Industrial Users GroupMISO
                  Midwest
                      Independent Transmission System Operator, Inc.MOU
                  Memorandum
                      of
                      UnderstandingMSG
                  Market
                      Support GenerationMTC
                  Market
                      Transition ChargeMW
                  MegawattsNAAQS
                  National
                      Ambient Air Quality StandardsNERC
                  North
                      American Electric Reliability CouncilNJBPU
                  New
                      Jersey
                      Board of Public UtilitiesNOAC
                  Northwest
                      Ohio Aggregation CoalitionNOV
                  Notices
                      of
                      ViolationNOx
                  Nitrogen
                      OxideNRC
                  Nuclear
                      Regulatory CommissionNUG
                  Non-Utility
                      GenerationOCA
                  Office
                      of
                      Consumer AdvocateOCC
                  Ohio
                      Consumers' CounselOCI
                  Other
                      Comprehensive IncomeOPAE
                  Ohio
                      Partners
                      for Affordable EnergyOPEB
                  Other
                      Post-Employment BenefitsOSBA
                  Office
                      of
                      Small Business AdvocateOTS
                  Office
                      of
                      Trial StaffPCAOB
                  Public
                      Company Accounting Oversight Board (United States)PCRBs
                  Pollution
                      Control Revenue BondsPICA
                  Penelec
                      Industrial Customer AssociationPJM
                  PJM
                      Interconnection, L.L.C.PLR
                  Provider
                      of
                      Last ResortPPUC
                  Pennsylvania
                      Public Utility CommissionPRP
                  Potentially
                      Responsible PartyPSA
                  Purchase
                      and
                      Sale AgreementPUCO
                  Public
                      Utilities Commission of OhioPUHCA
                  Public
                      Utility Holding Company Act of 1935RCP
                  Rate
                      Certainty PlanRSP
                  Rate
                      Stabilization PlanRTC
                  Regulatory
                      Transition ChargeS&P
                  Standard
                      & Poor’s Ratings ServiceSBC
                  Societal
                      Benefits ChargeSEC
                  United
                      States
                      Securities and Exchange CommissionSFAS
                  Statement
                      of
                      Financial Accounting StandardsSFAS
                      71
                  SFAS
                      No. 71,
                      "Accounting for the Effects of Certain Types of
                      Regulation"SFAS
                      123
                  SFAS
                      No. 123,
                      "Accounting for Stock-Based Compensation"SFAS
                      123(R)
                  SFAS
                      No. 123
                      (revised 2004), “Share-Based Payment”SFAS
                      131
                  SFAS
                      No. 131,
                      “Disclosures about Segments of an Enterprise and Related
                      Information”SFAS
                      133
                  SFAS
                      No. 133,
                      “Accounting for Derivative Instruments and Hedging
                      Activities”SFAS
                      140
                  SFAS
                      No. 140,
                      “Accounting for Transfers and Servicing of Financial Assets
                      andExtinguishment
                      of Liabilities”SFAS
                      144
                  SFAS
                      No. 144,
                      "Accounting for the Impairment or Disposal of Long-Lived
                      Assets"SFAS
                      153
                  SFAS
                      No. 153,
                      “Exchanges of Nonmonetary Assets - an amendment of APB Opinion
                      No.
                      29”


iv




SFAS
                    154
                SFAS
                    No. 154,
                    “Accounting Changes and Error Corrections - a replacement of APB
                    Opinion
                    No.
                  20
                    and FASB
                    Statement No. 3”SO2
                Sulfur
                    DioxideTBC
                Transition
                    Bond ChargeTMI-2
                Three
                    Mile
                    Island Unit 2UWUA
                Utility
                    Workers Union of AmericaVIE
                Variable
                    Interest Entity
 
 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, FESC, FSG and MYR.
 
 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,
        2004 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 6). As discussed
        in Note 16, interim period segment reporting in 2004 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 11)
        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.
 
 **2
        -
        ACCOUNTING FOR CERTAIN WHOLESALE ENERGY TRANSACTIONS**
 
 FES
        engages in
        purchase and sale transactions in the PJM Market to support the supply of
        end-use customers, including PLR requirements in Pennsylvania. In conjunction
        with FirstEnergy's dedication of its Beaver Valley Plant to PJM on
        January 1, 2005, FES
        began
        accounting for purchase and sale transactions in the PJM Market based on
        its net
        hourly position -- recording each hour as either an energy purchase in Fuel
        and
        purchased power expense or an energy sale, respectively, in the Consolidated
        Statements of Income relating to the Power Supply Management Services segment.
        Hourly energy positions are aggregated to recognize gross purchases and sales
        for the month.


1
  This
          revised method
          of accounting, which has no impact on net income, is consistent with the
          practice of other energy companies that have dedicated generating capacity
          to
          PJM and correlates with PJM's scheduling and reporting of hourly energy
          transactions. FES also applies the net hourly methodology to purchase and
          sale
          transactions in MISO's energy market, which became active on April 1,
          2005.
 
 For
          periods prior
          to January 1, 2005, FirstEnergy did not have substantial generating
          capacity in PJM and as such, FES recognized purchases and sales in the
          PJM
          Market by recording each discrete transaction. Under these transactions,
          FES
          would often buy a specific quantity of energy at a certain location in
          PJM and
          simultaneously sell a specific quantity of energy at a different location.
          Physical delivery occurred and the risks and rewards of ownership transferred
          with each transaction. FES
          accounted for
          those transactions on a gross basis in accordance with EITF 99-19.
 
 At
          its September
          2005 meeting, the FASB's EITF reached a final consensus on EITF 04-13,
          which
          relates to the accounting for purchases and sales of inventory with the
          same
          counterparty. The Task Force concluded that two or more transactions with
          the
          same counterparty should be viewed as a single nonmonetary transaction
          within
          the scope of APB 29, when the transactions are entered into "in contemplation"
          of one another. The consensus will be effective for new arrangements entered
          into, or modifications of existing arrangements, in interim or annual periods
          beginning after March 15, 2006. Retrospective application to prior
          transactions and/or restatement of prior period financial statements is
          not
          permitted. Accordingly, EITF 04-13 is not applicable to FES' purchases
          and sales
          in the PJM Market made prior to January 1, 2005. The recognition
          of these
          transactions on a net basis in 2004 would have no impact on net income,
          but
          would have reduced both wholesale revenue and purchased power expense by
          $264
          million and $828 million for the three months and nine months ended
          September 30, 2004, respectively.
 
 **3
          -
          DEPRECIATION**
 
 During
          the second
          half of 2004, FirstEnergy engaged an independent third party to assist
          in
          reviewing the service lives of its fossil generation units. This study
          was
          completed in the first quarter of 2005. As a result of the analysis, FirstEnergy
          extended the estimated service lives of its fossil generation units for
          periods
          ranging from 11 to 33 years during the first quarter of 2005. Extension
          of the
          service lives will provide improved matching of depreciation expense with
          the
          expected economic lives of those generation units.
 
 **4
          -
          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.
          Stock-based awards during the nine months ended September 30, 2004,
          to
          purchase 3.4 million shares of common stock were excluded from the calculation
          of diluted earnings per share of common stock because their exercise prices
          were
          greater than the average market price of common shares during the period.
          No
          stock-based awards were excluded from the calculation in the three months
          ended
          September 30, 2005 and 2004, and the nine months ended September 30,
          2005. The following table reconciles the denominators for basic and diluted
          earnings per share from Income Before Discontinued Operations:
 
 **Three
                  Months Ended**
              
              **Nine
                  Months Ended****September
                  30,**
              
              **September
                  30,****Reconciliation
                  of Basic and Diluted Earnings per Share**
              
              **2005**
              
              **2004**
              
              **2005**
              
              **2004*****(In
                  thousands, except per share amounts)***Income
                  Before
                  Discontinued Operations
              
              $
              331,832
              
              $
              296,125
              
              $
              651,627
              
              $
              670,334Average
                  Shares of Common Stock Outstanding:Denominator
                  for basic earnings per share(weighted
                  average shares outstanding)
              
              
              328,119
              
              
              327,499
              
              
              328,030
              
              
              327,280Assumed
                  exercise of dilutive stock options and awards
              
              
              2,074
              
              
              1,600
              
              
              1,896
              
              
              1,570Denominator
                  for diluted earnings per share
              
              
              330,193
              
              
              329,099
              
              
              329,926
              
              
              328,850Income
                  Before
                  Discontinued Operations per Common Share:Basic
              
              
              $1.01
              
              
              $0.90
              
              
              $1.99
              
              
              $2.05Diluted
              
              
              $1.01
              
              
              $0.90
              
              
              $1.98
              
              
              $2.04
 
  2
 **5
          -
          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 would make such an evaluation more frequently if
          indicators of impairment should 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 2005 annual review was completed in the third
          quarter of 2005 with no impairment indicated.
 
 FirstEnergy's
          goodwill primarily relates to its regulated services segment. In the nine
          months
          ended September 30, 2005, FirstEnergy adjusted goodwill related
          to the
          divestiture of non-core operations (FES' retail natural gas business, MYR's
          Power Piping Company subsidiary, and a portion of its interest in FirstCom)
          as
          further discussed in Note 6. In addition, adjustments to the former GPU
          and
          Centerior companies' goodwill were recorded to reverse pre-merger tax accruals
          due to final resolution of these tax contingencies. FirstEnergy estimates
          that
          completion of transition cost recovery (see Note 14) will not result in
          an
          impairment of goodwill relating to its regulated business segment. A summary
          of
          the changes in goodwill for the three months and nine months ended
          September 30, 2005 is shown below.
 **Three
                  Months Ended**
              
              **FirstEnergy**
              
              **CEI**
              
              **TE**
              
              **JCP&L**
              
              **Met-Ed**
              
              **Penelec*****(In
                  millions)***Balance
                  as of
                  July 1, 2005
              
              $
              6,033
              
              $
              1,694
              
              $
              505
              
              $
              1,984
              
              $
              868
              
              $
              887Pre-merger
                  tax adjustments related to Centerior acquisition
              
              
              (9
              )
              
              (5
              )
              
              (4
              )
              
              -
              
              
              -
              
              
              -Balance
                  as of
                  September 30, 2005
              
              $
              6,024
              
              $
              1,689
              
              $
              501
              
              $
              1,984
              
              $
              868
              
              $
              887
 
 **Nine
                  Months Ended**
              
              **FirstEnergy**
              
              **CEI**
              
              **TE**
              
              **JCP&L**
              
              **Met-Ed**
              
              **Penelec*****(In
                  millions)***Balance
                  as of
                  January 1, 2005
              
              $
              6,050
              
              $
              1,694
              
              $
              505
              
              $
              1,985
              
              $
              870
              
              $
              888Non-core
                  asset sales
              
              
              (13
              )
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Pre-merger
                  tax adjustments related to Centerior acquisition
              
              
              (9
              )
              
              (5
              )
              
              (4
              )
              
              -
              
              
              -
              
              
              -Pre-merger
                  tax adjustments related to GPU acquisition
              
              
              (4
              )
              
              -
              
              
              -
              
              
              (1
              )
              
              (2
              )
              
              (1
              )Balance
                  as of
                  September 30, 2005
              
              $
              6,024
              
              $
              1,689
              
              $
              501
              
              $
              1,984
              
              $
              868
              
              $
              887
 
 **6
          -
          DIVESTITURES AND DISCONTINUED OPERATIONS**
 
 In
          December 2004,
          FES' retail natural gas business qualified as assets held for sale in accordance
          with SFAS 144. On March 31, 2005, FES completed the sale for an
          after-tax
          gain of $5 million. In March 2005, FirstEnergy sold 51% of its interest
          in
          FirstCom, resulting in an after-tax gain of $4 million. FirstEnergy accounts
          for
          its remaining 31.85% interest in FirstCom on the equity basis.
 
 During
          the nine
          months ended September 30, 2005, FirstEnergy sold certain of its
          FSG
          subsidiaries (Elliott-Lewis, Spectrum and Cranston), and MYR’s Power Piping
          Company subsidiary, resulting in an after-tax gain of $12 million.
          FSG's
          remaining subsidiaries qualify as assets held for sale in accordance with
          SFAS
          144 and are expected to be recognized as completed sales within one year.
          The
          assets and liabilities of these remaining FSG subsidiaries are not material
          to
          FirstEnergy’s Consolidated Balance Sheet as of September 30, 2005, and
          therefore have not been separately classified as assets held for
          sale.
 
 As
          of
          September 30, 2005, the remaining FSG businesses do not meet the
          criteria
          for discontinued operations; therefore, the net results from these subsidiaries
          have been included in continuing operations. See Note 16 for FSG's segment
          financial information.
 
 Operating
          results
          from discontinued operations (including the gains on sales of assets discussed
          above) for Elliott-Lewis, Cranston, Power Piping and FES' retail natural
          gas
          business are summarized as follows:
 
 **Three
                  Months Ended**
              
              **Nine
                  Months Ended****September
                  30,**
              
              **September
                  30,****2005**
              
              **2004**
              
              **2005**
              
              **2004*****(In
                  millions)***Revenues
              
              $
              1
              
              $
              151
              
              $
              214
              
              $
              508Income
                  before
                  income taxes
              
              $
              1
              
              $
              4
              
              $
              10
              
              $
              10Income
                  from
                  discontinued operations, net of tax
              
              $
              1
              
              $
              3
              
              $
              19
              
              $
              6
   3
  The
        following table
        summarizes the sources of income from discontinued operations.
 
 **Three
                  Months Ended**
              
              **Nine
                  Months Ended****September
                  30,**
              
              **September
                  30,****2005**
              
              **2004**
              
              **2005**
              
              **2004*****(In
                  millions)***Discontinued
                  operations (net of tax)Gain
                  on
                  sale:Retail
                  gas
                  business
              
              $
              -
              
              $
              -
              
              $
              5
              
              $
              -FSG
                  and MYR
                  subsidiaries
              
              
              -
              
              
              -
              
              
              12
              
              
              -Reclassification
                  of operating income, net of tax
              
              
              1
              
              
              3
              
              
              2
              
              
              6Total
              
              $
              1
              
              $
              3
              
              $
              19
              
              $
              6
 
 **7
          -
          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, and to a lesser extent, for trading purposes.
          FirstEnergy’s Risk Policy Committee, comprised of members of senior management,
          provides general management oversight to risk management activities throughout
          the Company.
 
 FirstEnergy
          accounts for derivative instruments on its Consolidated Balance Sheet at
          their
          fair value unless they meet the normal purchase and normal sales criteria.
          Derivatives that meet that criteria are accounted for on the accrual basis.
          The
          changes in the fair value of a derivative instrument are recorded in current
          earnings, in other comprehensive income, 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
          has
          entered into 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 third
          quarter of 2005, FirstEnergy unwound swaps with a total notional amount
          of $350
          million from which it received immaterial net cash gains. The gains will
          be
          recognized in earnings over the remaining maturity of each respective hedged
          security as reduced interest expense. As of September 30, 2005,
          the
          aggregate notional value of interest rate swap agreements outstanding was
          $1.05
          billion.
 
 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 impact of ineffectiveness on earnings during the three months and nine
          months ended September 30, 2005 was not material.
 
 During
          the third
          quarter of 2005, 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 possible issuances of fixed-rate,
          long-term debt securities for one or more of its consolidated entities
          in the
          second half of 2006 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. As of
          September 30, 2005, FirstEnergy had entered into forward swaps with
          an
          aggregate notional amount of $500 million. As of September 30, 2005
          the
          forward swaps had a fair value of $2 million.
 
 The
          net deferred
          losses of $79 million included in AOCL as of September 30, 2005,
          for
          derivative hedging activity, as compared to the December 31, 2004
          balance
          of $92 million of net deferred losses, resulted from a $6 million
          decrease
          related to current hedging activity, a $4 million increase due to the sale
          of
          gas business contracts and an $11 million decrease due to net hedge
          losses
          included in earnings during the nine months ended September 30,
          2005.
          Approximately $14 million of the net deferred losses on derivative instruments
          in AOCL as of September 30, 2005 is expected to be reclassified
          to earnings
          during the next twelve months as hedged transactions occur. The fair value
          of
          these derivative instruments will fluctuate from period to period based
          on
          various market factors.
 
 FirstEnergy
          trades
          commodity derivatives and periodically experiences net open positions.
          FirstEnergy’s risk management policies limit the exposure to market risk from
          open positions and require daily reporting to management of potential financial
          exposures. During the three months and nine months ended September 30,
          2005, the effect of trading on earnings was not material.
  4
  **8
          - STOCK
          BASED COMPENSATION**
  FirstEnergy
          applies
          the recognition and measurement principles of APB 25 and related interpretations
          in accounting for its stock-based compensation plans. No material stock-based
          employee compensation expense is reflected in net income for 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.
 
 In
          December 2004,
          the FASB issued SFAS 123(R), a revision to SFAS 123 which requires expensing
          the
          fair value of stock options (see Note 15). In April 2005, the SEC delayed
          the
          effective date of SFAS 123(R) to annual, rather than interim, periods that
          begin
          after June 15, 2005. FirstEnergy will be required to adopt this
          standard
          beginning January 1, 2006. The table below summarizes the effects
          on
          FirstEnergy’s net income and earnings per share had FirstEnergy applied the fair
          value recognition provisions of SFAS 123(R) to stock-based employee compensation
          in the current reporting periods.
 
 **Three
                  Months Ended**
              
              **Nine
                  Months Ended****September
                  30,**
              
              **September
                  30,****2005**
              
              **2004**
              
              **2005**
              
              **2004*****(In
                  thousands, except per share amounts)***Net
                  income,
                  as reported
              
              
              
              $
              332,360
              
              $
              298,622
              
              $
              670,078
              
              $
              676,666Add
                  back
                  compensation expensereported
                  in
                  net income, net of tax(based
                  on APB
                  25)(1)
              
              
              
              
              17,404
              
              
              13,549
              
              
              39,785
              
              
              29,355Deduct
                  compensation expense basedupon
                  estimated fair value, net of tax(2)
              
              
              
              
              (18,378
              )
              
              (16,981
              )
              
              (44,825
              )
              
              (40,380
              )Net
                  income,
                  as adjusted
              
              
              
              $
              331,386
              
              $
              295,190
              
              $
              665,038
              
              $
              665,641Earnings
                  Per
                  Share of Common Stock -BasicAs
                  reported
              
              
              
              
              $1.01
              
              
              $0.91
              
              
              $2.04
              
              
              $2.07As
                  adjusted
              
              
              
              
              $1.01
              
              
              $0.90
              
              
              $2.03
              
              
              $2.03DilutedAs
                  reported
              
              
              
              
              $1.01
              
              
              $0.91
              
              
              $2.03
              
              
              $2.06As
                  adjusted
              
              
              
              
              $1.00
              
              
              $0.90
              
              
              $2.02
              
              
              $2.02(1)Includes
                  restricted stock, restricted stock units, stock options, performance
                  shares, Employee Stock
                Ownership
                  Plan,Executive
                  Deferred Compensation Plan and Deferred Compensation Plan for
                  outsideDirectors.(2)Assumes
                  vesting at age 65.
 
 FirstEnergy
          reduced
          the use of stock options in 2005 and increased the use of performance-based,
          restricted stock units. Therefore, the pro forma effects of applying SFAS
          123(R)
          may not be representative of its future effect. FirstEnergy does not expect
          to
          accelerate out-of-the-money options in anticipation of implementing SFAS
          123(R)
          on January 1, 2006.
 
 **9
          - ASSET
          RETIREMENT OBLIGATIONS**
  FirstEnergy
          has
          identified applicable legal obligations for nuclear power plant decommissioning,
          reclamation of a sludge disposal pond related to the Bruce Mansfield Plant
          and
          closure of two coal ash disposal sites. The ARO liability of $1.130 billion
          as
          of September 30, 2005 included $1.115 billion for nuclear decommissioning
          of the Beaver Valley, Davis-Besse, Perry and TMI-2 nuclear generating
          facilities. The Companies' share of the obligation to decommission these
          units
          was developed based on site specific studies performed by an independent
          engineer. FirstEnergy utilized an expected cash flow approach to measure
          the
          fair value of the nuclear decommissioning ARO.
 
 In
          the third
          quarter of 2005, FirstEnergy revised the ARO associated with Beaver Valley
          Units
          1 and 2 as a result of an updated decommissioning study. The present value
          of
          revisions in the estimated cash flows associated with projected decommissioning
          costs increased the ARO for Beaver Valley Unit 1 by $21 million and decreased
          the ARO for Beaver Valley Unit 2 by $22 million, resulting in a net decrease
          in
          the ARO liability and corresponding plant asset of $1 million (OE
          - ($2)
          million, CEI - ($5) million, TE - ($5) million and Penn - $11
          million).
 
 The
          Companies
          maintain trust funds that are legally restricted for purposes of settling
          the
          nuclear decommissioning ARO. As of September 30, 2005, the fair
          value of
          the decommissioning trust assets was $1.7 billion.
   5
  The
          following
          tables analyze changes to the ARO balance during the three months and nine
          months ended September 30, 2005 and 2004, respectively.
 
 **Three
                  Months Ended**
              
              **FirstEnergy**
              
              **OE**
              
              **CEI**
              
              **TE**
              
              **Penn**
              
              **JCP&L**
              
              **Met-Ed**
              
              **Penelec*****(In
                  millions)***Balance,
                  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
                  estimatedcash
                  flows
              
              
              (1
              )
              
              (2
              )
              
              (5
              )
              
              (5
              )
              
              11
              
              
              -
              
              
              -
              
              
              -Balance,
                  September 30, 2005
              
              $
              1,130
              
              $
              209
              
              $
              281
              
              $
              200
              
              $
              156
              
              $
              76
              
              $
              139
              
              $
              69Balance,
                  July
                  1, 2004
              
              $
              1,217
              
              $
              194
              
              $
              263
              
              $
              188
              
              $
              134
              
              $
              113
              
              $
              216
              
              $
              108Liabilities
                  incurred
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Liabilities
                  settled
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Accretion
              
              
              19
              
              
              4
              
              
              5
              
              
              3
              
              
              2
              
              
              2
              
              
              3
              
              
              1Revisions
                  in
                  estimatedcash
                  flows
              
              
              (176
              )
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              (43
              )
              
              (89
              )
              
              (44
              )Balance,
                  September 30, 2004
              
              $
              1,060
              
              $
              198
              
              $
              268
              
              $
              191
              
              $
              136
              
              $
              72
              
              $
              130
              
              $
              65
 
 
 **Nine
                  Months Ended**
              
              **FirstEnergy**
              
              **OE**
              
              **CEI**
              
              **TE**
              
              **Penn**
              
              **JCP&L**
              
              **Met-Ed**
              
              **Penelec*****(In
                  millions)***Balance,
                  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
                  estimatedcash
                  flows
              
              
              (1
              )
              
              (2
              )
              
              (5
              )
              
              (5
              )
              
              11
              
              
              -
              
              
              -
              
              
              -Balance,
                  September 30, 2005
              
              $
              1,130
              
              $
              209
              
              $
              281
              
              $
              200
              
              $
              156
              
              $
              76
              
              $
              139
              
              $
              69Balance,
                  January 1, 2004
              
              $
              1,179
              
              $
              188
              
              $
              255
              
              $
              182
              
              $
              130
              
              $
              110
              
              $
              210
              
              $
              105Liabilities
                  incurred
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Liabilities
                  settled
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Accretion
              
              
              57
              
              
              10
              
              
              13
              
              
              9
              
              
              6
              
              
              5
              
              
              9
              
              
              4Revisions
                  in
                  estimatedcash
                  flows
              
              
              (176
              )
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              (43
              )
              
              (89
              )
              
              (44
              )Balance,
                  September 30, 2004
              
              $
              1,060
              
              $
              198
              
              $
              268
              
              $
              191
              
              $
              136
              
              $
              72
              
              $
              130
              
              $
              65
 
 **10
        -
        PENSION AND OTHER POSTRETIREMENT BENEFITS:**
  The
          components of
          FirstEnergy's net periodic pension cost and other postretirement benefits
          cost
          (including amounts capitalized) for the three months and nine months ended
          September 30, 2005 and 2004, consisted of the following:
 
 **Three
                  Months Ended**
              **Nine
                  Months Ended****September
                  30,**
              
              **September
                  30,****Pension
                  Benefits**
              
              **2005**
              
              **2004**
              
              **2005**
              
              **2004*****(In
                  millions)***Service
                  cost
              
              $
              19
              
              $
              19
              
              $
              58
              
              $
              58Interest
                  cost
              
              
              64
              
              
              63
              
              
              191
              
              
              189Expected
                  return on plan assets
              
              
              (86
              )
              
              (71
              )
              
              (259
              )
              
              (215
              )Amortization
                  of prior service cost
              
              
              2
              
              
              2
              
              
              6
              
              
              7Recognized
                  net actuarial loss
              
              
              9
              
              
              10
              
              
              27
              
              
              29Net
                  periodic
                  cost
              
              $
              8
              
              $
              23
              
              $
              23
              
              $
              68
 
 
  6
   **Three
                  Months Ended**
              
              **Nine
                  Months Ended****September
                  30,**
              
              **September
                  30,****Other
                  Postretirement Benefits**
              
              **2005**
              
              **2004**
              
              **2005**
              
              **2004*****(In
                  millions)***Service
                  cost
              
              $
              10
              
              $
              9
              
              $
              30
              
              $
              27Interest
                  cost
              
              
              27
              
              
              26
              
              
              83
              
              
              83Expected
                  return on plan assets
              
              
              (11
              )
              
              (10
              )
              
              (34
              )
              
              (32
              )Amortization
                  of prior service cost
              
              
              (11
              )
              
              (9
              )
              
              (33
              )
              
              (28
              )Recognized
                  net actuarial loss
              
              
              10
              
              
              9
              
              
              30
              
              
              29Net
                  periodic
                  cost
              
              $
              25
              
              $
              25
              
              $
              76
              
              $
              79
 
 Pension
          and
          postretirement benefit obligations are allocated to the FirstEnergy subsidiaries
          employing the plan participants. The Companies capitalize employee benefits
          related to construction projects. The net periodic pension benefits (credit)
          and
          net periodic postretirement benefits (including amounts capitalized) recognized
          by each of the Companies in the three months and nine months ended
          September 30, 2005 and 2004 were as follows:
 
 **Three
                  Months Ended**
              
              **Nine
                  Months Ended****September
                  30,**
              
              **September
                  30,****Pension
                  Benefits (Credit)**
              
              **2005**
              
              **2004**
              
              **2005**
              
              **2004*****(In
                  millions)***OE
              
              $
              0.2
              
              $
              1.7
              
              $
              0.7
              
              $
              5.2Penn
              
              
              (0.2
              )
              
              0.1
              
              
              (0.7
              )
              
              0.4CEI
              
              
              0.3
              
              
              1.6
              
              
              1.0
              
              
              4.8TE
              
              
              0.3
              
              
              0.8
              
              
              1.0
              
              
              2.3JCP&L
              
              
              (0.3
              )
              
              1.9
              
              
              (0.8
              )
              
              5.6Met-Ed
              
              
              (1.1
              )
              
              0.1
              
              
              (3.2
              )
              
              0.2Penelec
              
              
              (1.3
              )
              
              0.1
              
              
              (4.0
              )
              
              0.4
 
 
 **Three
                  Months Ended**
              
              **Nine
                  Months Ended****September
                  30,**
              
              **September
                  30,****Other
                  Postretirement Benefits**
              
              **2005**
              
              **2004**
              
              **2005**
              
              **2004*****(In
                  millions)***OE
              
              $
              5.8
              
              $
              5.7
              
              $
              17.3
              
              $
              17.7Penn
              
              
              1.2
              
              
              1.2
              
              
              3.5
              
              
              3.7CEI
              
              
              3.8
              
              
              4.4
              
              
              11.4
              
              
              13.7TE
              
              
              2.2
              
              
              1.7
              
              
              6.5
              
              
              5.0JCP&L
              
              
              1.5
              
              
              1.0
              
              
              5.7
              
              
              3.5Met-Ed
              
              
              0.4
              
              
              0.7
              
              
              1.2
              
              
              2.5Penelec
              
              
              2.0
              
              
              0.7
              
              
              5.9
              
              
              2.5
 
 **11
        -
        VARIABLE INTEREST ENTITIES**
 
 **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 three-percent equity interest
          by a
          nonaffiliated third party and a three-percent 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 and leaseback
          agreements, OE, CEI and TE have net minimum discounted lease payments of
          $678
          million, $103 million and $541 million, respectively, that would not be
          payable
          if the casualty value payments are made.
  7
  **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
          structured 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. The maximum exposure to loss from these entities results
          from
          increases in the variable pricing component under the contract terms and
          cannot
          be determined without the requested data. Purchased power costs from these
          entities during the three months and nine months ended September 30,
          2005
          and 2004 are shown in the table below:
  **Three
                    Months Ended**
                
                **Nine
                    Months Ended****September
                    30,**
                
                **September
                    30,****2005**
                
                **2004**
                
                **2005**
                
                **2004*****(In
                    millions)***JCP&L
                $
                33
                
                $
                26
                
                $
                74
                
                $
                71Met-Ed
                
                10
                
                
                13
                
                
                40
                
                
                38Penelec
                
                7
                
                
                7
                
                
                21
                
                
                20Total
                $
                50
                
                $
                46
                
                $
                135
                
                $
                129
    **Securitized
          Transition Bonds**
 The
            consolidated
            financial statements of FirstEnergy and JCP&L include the results of
            JCP&L Transition, a wholly owned limited liability company of JCP&L. In
            June 2002, JCP&L Transition 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.
 
 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 obligations of JCP&L Transition only and are
            collateralized solely by the equity and assets of JCP&L Transition, which
            consist primarily of bondable transition property. The bondable transition
            property is solely the property of JCP&L Transition.
 
 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 the transition
            bonds
            and other fees and expenses associated with their issuance. JCP&L sold the
            bondable transition property to JCP&L Transition and, as servicer, manages
            and administers the bondable transition property, including the billing,
            collection and remittance of the TBC, pursuant to a servicing agreement
            with
            JCP&L Transition. JCP&L is entitled to a quarterly servicing fee of $0.1
            million that is payable from TBC collections.
 
 **12
        - OHIO
        TAX LEGISLATION**
  On
          June 30,
          2005, the State of Ohio enacted tax legislation that creates a new CAT
          tax,
          which is based on qualifying “taxable gross receipts” and will not consider any
          expenses or costs incurred to generate such receipts, except for items
          such as
          cash discounts, returns and allowances, and bad debts. The CAT tax was
          effective
          July 1, 2005, and replaces the Ohio income-based franchise tax and
          the Ohio
          personal property tax. The CAT tax is phased-in while the current income-based
          franchise tax is phased-out over a five-year period at a rate of 20% annually,
          beginning with the year ended 2005, and the personal property tax is phased-out
          over a four-year period at a rate of approximately 25% annually, beginning
          with
          the year ended 2005. For example, during the phase-out period the Ohio
          income-based franchise tax will be computed consistently with the prior
          tax law,
          except that the tax liability as computed will be multiplied by 4/5 in
          2005; 3/5
          in 2006; 2/5 in 2007 and 1/5 in 2008, therefore eliminating the current
          income-based franchise
          tax over
          a five-year period. As a result of the new tax structure, all net deferred
          tax
          benefits that were not expected to reverse during the five-year phase-in
          period
          were written-off as of June 30, 2005.
   8
 
 The
          increase (in
          millions) to income taxes associated with the adjustment to net deferred
          taxes
          for the nine months ended September 30, 2005 is summarized
          below:
 
 OE
              
              $
              36.0CEI
              
              
              7.5TE
              
              
              17.5Other
                  FirstEnergy subsidiaries
              
              
              10.7Total
                  FirstEnergy
              
              $
              71.7
 
 Income
          tax expenses
          were (increased) reduced during the three months and nine months ended
          September 30, 2005 by the initial phase-out of the Ohio income-based
          franchise tax and phase-in of the CAT tax as summarized below :
  **Three
                      Months Ended**
                  
                  
                  **Nine
                      Months Ended****September
                      30, 2005**
                  
                  **September
                      30, 2005*****(In
                      millions)***OE
                  
                  $
                  1.6
                  
                  $
                  6.5CEI
                  
                  
                  (3.1
                  )
                  
                  (1.7
                  )TE
                  
                  
                  0.7
                  
                  
                  1.2Other
                      FirstEnergy subsidiaries
                  
                  
                  0.7
                  
                  
                  1.5Total
                      FirstEnergy
                  
                  $
                  (0.1
                  )
                  $
                  7.5
   **13
        -
        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.
          Such agreements include contract guarantees, surety bonds and ratings contingent
          collateralization provisions. As of September 30, 2005, outstanding
          guarantees and other assurances aggregated approximately $2.7 billion and
          included contract guarantees ($1.3 billion), surety bonds ($0.3 billion)
          and LOCs ($1.1 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 subsidiary
          financing principally for the acquisition of 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. Such parental guarantees
          amount to $0.8 billion (included in the $1.3 billion discussed above) as
          of
          September 30, 2005 and the likelihood is remote that such guarantees
          will
          increase amounts otherwise to be paid by FirstEnergy to meet its obligations
          incurred in connection with financings and ongoing energy and energy-related
          contracts.
 
 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. The
          following table summarizes collateral provisions in effect as of
          September 30, 2005:
 **Total**
              
              **Collateral
                  Paid**
              
              **Remaining****Collateral
                  Provisions**
              
              
              **Exposure**
              
              **Cash**
              
              **LOC**
              
              **Exposure*****(In
                  millions)***Credit
                  rating
                  downgrade
              
              
              
              $
              445
              
              $
              213
              
              $
              18
              
              $
              214Adverse
                  event
              
              
              
              
              77
              
              
              -
              
              
              5
              
              
              72Total
              
              
              
              $
              522
              
              $
              213
              
              $
              23
              
              $
              286
 
 On
          October 3,
          2005, S&P raised the senior unsecured ratings of FirstEnergy's holding
          company to 'BBB-' from 'BB+'. As a result of the rating upgrade, $109 million
          of
          cash collateral was subsequently returned to FirstEnergy.
 9
  
 Most
          of
          FirstEnergy's surety bonds are backed by various indemnities common within
          the
          insurance industry. Surety bonds and related FirstEnergy guarantees of
          $307
          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.
 
 **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
          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 ($47 million as of
          September 30, 2005) which is renewable and declines yearly based
          upon the
          senior outstanding debt of TEBSA. The LOC was reduced to $36 million on
          October
          15, 2005.
 
 **(B)**  **ENVIRONMENTAL
          MATTERS**
 
 Various
          federal,
          state and local authorities regulate the Companies 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. These environmental
          regulations affect 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 $670 million for 2005 through 2007.
  The
          Companies
          accrue environmental liabilities only when they conclude that it is probable
          that they have an obligation for such costs and can reasonably estimate
          the
          amount of such costs. Unasserted claims are reflected in the Companies’
          determination of environmental liabilities and are accrued in the period
          that
          they are both probable and reasonably estimable.
  FirstEnergy
          plans
          to issue a report regarding its response to air emission requirements.
          FirstEnergy expects to complete the report by December 1,
          2005.
 
 *Clean
          Air Act
          Compliance*
  FirstEnergy
          is
          required to meet federally approved SO 2 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. The
          Companies cannot predict what action the EPA may take in the future with
          respect
          to the interim enforcement policy.
 
 FirstEnergy
          believes it is complying 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 from
          FirstEnergy's facilities. The EPA's NO x Transport Rule
          imposes uniform reductions of NO x emissions (an
          approximate 85 percent 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 State Implementation Plans 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 proposed a new NAAQS
          for fine
          particulate matter. On March 10, 2005, the EPA finalized the "Clean
          Air
          Interstate Rule" 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 nonattainment 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 )
          in all cases from
          the 2003 levels. FirstEnergy's Michigan, Ohio and Pennsylvania fossil-fired
          generation facilities will be subject to the caps on SO 2 and NO x emissions, whereas
          their New Jersey fossil-fired generation facilities 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.
 
 *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. On March 14, 2005,
          the EPA
          finalized the "Clean Air Mercury Rule," 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 Clean Air Mercury Rule 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.
 
 *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, which is in the
          form of
          a Consent Decree, was approved by the Court on July 11, 2005, requires
          OE
          and Penn to reduce No x and SO 2 emissions at the
          W. H. Sammis Plant and other coal fired plants through the installation
          of
          pollution control devices. Capital expenditures necessary to meet those
          requirements are currently estimated to be $1.5 billion (the primary portion
          of
          which is expected to be spent in the 2008 to 2011 time period). As disclosed
          in
          FirstEnergy's Form 8-K dated August 26, 2005, FGCO entered into an agreement
          with Bechtel Power Corporation (Bechtel), under which Bechtel will engineer,
          procure, and construct air quality control systems for the reduction of
          sulfur
          dioxide emissions. 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 payable by OE and Penn of $7.8 million and $0.7
          million,
          respectively. OE and Penn also recognized liabilities of $9.2 million
          and
          $0.8 million, respectively, during the first quarter of 2005, 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 (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 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 percent through 2012. The
          Energy
          Policy Act of 2005 established a Committee on Climate Change Technology
          to
          coordinate federal climate change activities and promote the development
          and
          deployment of GHG reducing technologies.
  
 11
 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.
 
 *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.
 
 *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, 2005, based on estimates of the total costs of cleanup,
          the
          Companies' proportionate responsibility for such costs and the financial
          ability
          of other nonaffiliated 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 $64 million (JCP&L - $46.8 million, CEI - $2.3 million, TE - $0.2 million,
          Met-Ed - $0.1 million and
          other - $14.6 million)
          have been accrued through September 30, 2005.
 
 **(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. On September 8, 2004, the New Jersey Supreme Court denied
          the
          motions filed by plaintiffs and JCP&L for leave to appeal the decision of
          the Appellate Division. JCP&L has filed a motion for summary judgment.
          FirstEnergy is unable to predict the outcome of these matters and no liability
          has been accrued as of September 30, 2005.
  12
  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 website (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 also is proceeding with
          the
          implementation of the recommendations regarding enhancements to regional
          reliability 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, and therefore FirstEnergy has not accrued a liability as of
          September 30, 2005 for any expenditures in excess of those actually
          incurred through that date. 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 that
          could
          require additional, material expenditures. Finally, the PUCO is continuing
          to
          review FirstEnergy’s filing that addressed upgrades to control room computer
          hardware and software and enhancements to the training of control room
          operators, before determining the next steps, if any, in the
          proceeding.
 
 FirstEnergy
          companies also are defending six separate complaint cases before the PUCO
          relating to the August 14, 2003 power outage. 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. Of the four other pending PUCO complaint cases, three were
          filed by
          various insurance carriers either in their own name as subrogees or in
          the name
          of their insured. In each of the four cases, the carrier seeks reimbursement
          from various FirstEnergy companies (and, in one case, from PJM, MISO and
          American Electric Power Co. as well) for claims paid to insureds for claims
          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 fourth case involves the claim of a non-customer
          seeking reimbursement for losses incurred when its store was burglarized
          on
          August 14, 2003. In addition to these six cases, the Ohio Companies
          were
          named as respondents in a regulatory proceeding that was initiated at the
          PUCO
          in response to complaints alleging failure to provide reasonable and adequate
          service stemming primarily from the August 14, 2003 power outages.
          No
          estimate of potential liability has been undertaken for any of these cases.
 
 One
          complaint was
          filed on August 25, 2004 against FirstEnergy in the New York State Supreme
          Court. In this case, several plaintiffs in the New York City metropolitan
          area
          allege that they suffered damages as a result of the August 14,
          2003 power
          outages. None of the plaintiffs are customers of any FirstEnergy affiliate.
          FirstEnergy's motion to dismiss the case was granted on September 26,
          2005. Additionally, FirstEnergy Corp. was named in a complaint filed
          in
          Michigan State Court by an individual who is not a customer of any FirstEnergy
          company. A responsive pleading to this matter is not due until on or about
          December 1, 2005. No estimate of potential liability has been undertaken
          in this
          matter.
  13
  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.
 
 *Nuclear
          Plant
          Matters*
  FENOC
          received a
          subpoena in late 2003 from a grand jury sitting in the United States District
          Court for the Northern District of Ohio, Eastern Division requesting the
          production of certain documents and records relating to the inspection
          and
          maintenance of the reactor vessel head at the Davis-Besse Nuclear Power
          Station.
          On December 10, 2004, FirstEnergy received a letter from the United
          States
          Attorney's Office stating that FENOC is a target of the federal grand jury
          investigation into alleged false statements made to the NRC in the Fall
          of 2001
          in response to NRC Bulletin 2001-01. The letter also said that the designation
          of FENOC as a target indicates that, in the view of the prosecutors assigned
          to
          the matter, it is likely that federal charges will be returned against
          FENOC by
          the grand jury. On February 10, 2005, FENOC received an additional
          subpoena
          for documents related to root cause reports regarding reactor head degradation
          and the assessment of reactor head management issues at Davis-Besse. On
          May 11, 2005, FENOC received a subpoena for documents related to
          outside
          meetings attended by Davis-Besse personnel on corrosion and cracking of
          control
          rod drive mechanisms and additional root cause evaluations.
 
 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 described
          above.
          FirstEnergy accrued $2.0 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.
 
 If
          it were
          ultimately determined that FirstEnergy or its subsidiaries have legal liability
          based on the events surrounding Davis-Besse, it could have a material adverse
          effect on FirstEnergy's or its subsidiaries' financial condition, results
          of
          operations and cash flows.
 
 Effective
          July 1, 2005, the NRC oversight panel for Davis-Besse was terminated
          and
          Davis-Besse returned to the standard NRC reactor oversight process. At
          that
          time, NRC inspections were augmented to include inspections to support
          the NRC's
          Confirmatory Order dated March 8, 2004 that was issued at the time
          of
          startup and to address an NRC White Finding related to the performance
          of the
          emergency sirens.
 
 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, which
          is
          currently owned and/or leased by OE, CEI, TE and Penn (however, see Note
          17
          regarding FirstEnergy’s pending intra-system generation asset transfers, which
          will include owned portions of the 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
          May 26,
          2005, the NRC held a public meeting to discuss its oversight of the Perry
          Plant.
          While the NRC stated that the plant continued to operate safely, the NRC
          also
          stated that the overall performance had not substantially improved since
          the
          heightened inspection was initiated. The NRC reiterated this conclusion
          in its
          mid-year assessment letter dated August 30, 2005. On September 28,
          2005, the NRC sent a CAL to FENOC describing commitments that FENOC had
          made to
          improve the performance of Perry 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. 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. As a result, these
          matters could have a material adverse effect on FirstEnergy's or its
          subsidiaries' financial condition, results of operations and cash
          flows.
 14
  *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 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. 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 the 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.
 
 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 Arbitrator
        decided not to hear testimony on damages and closed the proceedings. On
        September 9, 2005, the Arbitrator issued an opinion to award approximately
        $16.1 million to the bargaining unit employees. JCP&L initiated an appeal of
        this award by filing a motion to vacate in Federal Court in New Jersey on
        October 18, 2005. JCP&L recognized a liability for the potential $16.1
        million award during the three months ended September 30,
        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. 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. It is unknown when the PUCO will rule on this case.
 
 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.
 
 **14
        -
        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, 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 Energy Policy Act of 2005
        that could require additional, material expenditures. Finally, the PUCO is
        continuing to review the FirstEnergy filing that addressed upgrades to control
        room computer hardware and software and enhancements to the training of control
        room operators, before determining the next steps, if any, in the proceeding.





15




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. On March 29,
        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 a
        Special
        Reliability Master 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 Ratepayer Advocate to discuss reliability improvements. JCP&L
        continues to file compliance reports reflecting activities associated with
        the
        MOU and Stipulation.
 
 In
        May 2004, the
        PPUC issued an order approving revised reliability benchmarks and standards,
        including revised benchmarks and standards for Met-Ed, Penelec and Penn.
        Met-Ed,
        Penelec and Penn filed a Petition for Amendment of Benchmarks with the PPUC
        on
        May 26, 2004, due to their implementation of automated outage management
        systems following restructuring. Evidentiary hearings have been scheduled
        for
        November 2005. FirstEnergy is unable to predict the outcome of this
        proceeding.
 
 The
        Energy Policy
        Act of 2005 provides for the creation of an ERO to establish and enforce
        reliability standards for the bulk power system, subject to FERC review.
        On
        September 1, 2005, the FERC issued a Notice of Proposed Rulemaking
        to
        establish certification requirements for the ERO, as well as regional entities
        envisioned to assume monitoring and compliance responsibility for the new
        reliability standards. The FERC expects to adopt a final rule on or before
        February 2006 regarding certification requirements for the ERO and regional
        entities.
 
 The
        NERC is
        expected to reorganize its structure to meet the FERC’s certification
        requirements for the ERO. Following adoption of the final rule, the NERC
        will be
        required to make a filing with the FERC to obtain certification as the ERO.
        The
        proposed rule also provides for regional reliability organizations designed
        to
        replace the current regional councils. 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 ECAR, Mid-Atlantic
        Area Council, and Mid-American Interconnected Network reliability
        councils have signed an MOU designed to consolidate their regions into a
        new
        regional reliability organization known as ReliabilityFirst Corporation.
        Their
        intent is to file and obtain certification under the final rule as a “regional
        entity”. All of FirstEnergy’s facilities would be located within the
        ReliabilityFirst region.
 
 On
        a parallel path,
        the NERC is establishing working groups to develop reliability standards
        to be
        filed for approval with the FERC following the NERC’s certification as an ERO.
        These reliability standards are expected to build on the current NERC Version
        0
        reliability standards. It is expected that the proposed reliability standards
        will be filed with the FERC in early 2006.
 
 The
        impact of this
        effort on FirstEnergy is unclear. FirstEnergy believes that it is in compliance
        with all current NERC reliability standards. However, it is expected that
        the
        FERC will adopt stricter reliability standards than those contained in the
        current NERC Version 0 standards. The financial impact of complying with
        the new
        standards cannot be determined at this time. However, the Energy Policy Act
        of
        2005 requires that all prudent costs incurred to comply with the new reliability
        standards be recovered in rates.
 
 **Ohio**
 
 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 competitive
        bid
        process. The RSP was filed by the Ohio Companies to establish generation
        service
        rates beginning January 1, 2006, in response to PUCO 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 this proceeding as well as the associated entries on rehearing. On
        September 28, 2005, the Ohio Supreme Court heard oral argument on
        the
        appeals.
 
 On
        May 27,
        2005, the Ohio Companies filed an application with the PUCO to establish
        a GCAF
        rider under the RSP. The application seeks to implement recovery of increased
        fuel costs from 2006 through 2008 applicable to the Ohio Companies' retail
        customers through a tariff rider to be implemented January 1, 2006.
        The
        application reflects projected increases in fuel costs in 2006 compared to
        2002
        baseline costs. The new rider, after adjustments made in testimony, is seeking
        to recover all costs above the baseline (approximately $88 million in 2006).
        Various parties including the OCC have intervened in this case and the case
        has
        been consolidated with the RCP application discussed below.


16




On
          September 9,
          2005, the Ohio Companies filed an application with the PUCO that, if approved,
          would supplement their existing RSP with an RCP. On September 27,
          2005, the
          PUCO granted FirstEnergy's motion to consolidate the GCAF rider application
          with
          the RCP proceedings and set hearings for the consolidated cases to begin
          November 29, 2005. The RCP is designed to provide customers with
          more
          certain rate levels than otherwise available under the RSP during the plan
          period. Major provisions of the RCP include:
 
 · Maintain
          the
          existing level of base distribution rates through December 31, 2008
          for OE
          and TE, and
 April 30,
          2009
          for CEI;
 
 · Defer
          and
          capitalize 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;
 
 · Adjust
          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;
 
 · Reduce
          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
 
 · Recover
          increased
          fuel costs 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
          and OE, TE, and CEI may defer and capitalize increased fuel costs above
          the
 amount
          collected
          through the fuel recovery mechanism.
 
 The
          following table
          provides a comparison of the estimated net amortization of regulatory transition
          costs and deferred shopping incentives (including associated carrying charges)
          under the proposed RCP and the current RSP for the period 2006 through
          2010:


**Estimated
                Net Amortization****RCP**
            
            **RSP****Amortization**
            
            
            
            
            
            
            
            **Total**
            
            
            
            
            
            
            
            **Total****Period**
            
            **OE**
            
            **CEI**
            
            **TE**
            
            **Ohio**
            
            **OE**
            
            **CEI**
            
            **TE**
            
            **Ohio*****(In
                millions)***2006
            
            $
            169
            
            $
            100
            
            $
            80
            
            $
            349
            
            $
            175
            
            $
            94
            
            $
            73
            
            $
            3422007
            
            
            176
            
            
            111
            
            
            89
            
            
            376
            
            
            237
            
            
            104
            
            
            82
            
            
            4232008
            
            
            198
            
            
            129
            
            
            100
            
            
            427
            
            
            206
            
            
            122
            
            
            159
            
            
            4872009
            
            
            -
            
            
            216
            
            
            -
            
            
            216
            
            
            -
            
            
            318
            
            
            -
            
            
            3182010
            
            
            -
            
            
            268
            
            
            -
            
            
            268
            
            
            -
            
            
            271
            
            
            -
            
            
            271**Net
                Amortization***
            
            **$**
            **543**
            
            **$**
            **824**
            
            **$**
            **269**
            
            **$**
            **1,636**
            
            **$**
            **618**
            
            **$**
            **909**
            
            **$**
            **314**
            
            **$**
            **1,841***
                RCP
                aggregate amortization is less than amortization under the RSP due
                to the
                accelerated application of regulatoryliabilities
                to reduce deferred shopping
                incentives.





Under
        provisions of
        the RSP, the PUCO may require the Ohio Companies to undertake, no more often
        than annually, a competitive bid process to secure generation for the years
        2007
        and 2008. On July 22, 2005, FirstEnergy filed a competitive bid process
        for
        the period beginning in 2007 that is similar to the competitive bid process
        approved by the PUCO for the Ohio Companies in 2004, which resulted in the
        PUCO
        accepting no bids. Any acceptance of future competitive bid results would
        terminate the RSP pricing, with no accounting impacts to the RSP, and not
        until
        twelve months after the PUCO authorizes such termination. On September 28,
        2005, the PUCO issued an Entry that essentially approved the Ohio Companies'
        filing but delayed the proposed timing of the competitive bid process by
        four
        months, calling for the auction to be held on March 21, 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.




17




In
        accordance with
        PPUC directives, Met-Ed and Penelec have been negotiating with interested
        parties in an attempt to resolve the merger savings issues that are the subject
        of remand from the Commonwealth Court. Met-Ed’s and Penelec’s combined portion
        of total merger savings is estimated to be approximately $31.5 million. On
        April 13, 2005, the Commonwealth Court issued an interim order in
        the
        remand proceeding that the parties should report the status of the negotiations
        to the PPUC with a copy to the ALJ. The parties exchanged settlement proposals
        in May and June 2005 and continue to have settlement discussions.
 
 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 judge, 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.
  Met-Ed
        and Penelec
        purchase a portion of their PLR requirements from FES through a wholesale
        power
        sales agreement. The PLR sale is automatically extended for each successive
        calendar year unless any party elects to cancel the agreement by November 1
        of the preceding year. Under the terms of the wholesale 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
        NUG contracts and other power contracts with nonaffiliated third party
        suppliers. This 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. Met-Ed and Penelec
        are authorized to defer differences between NUG contract costs and current
        market prices. On November
        1,
        2005, FES and the other parties to the wholesale power agreement amended
        the
        agreement to provide FES the right over the next year to terminate the agreement
        at any time upon 60 days notice.If
        the wholesale
        power agreement were terminated, Met-Ed and Penelec would need to satisfy
        the
        applicable portion of their PLR obligations from other sources at prevailing
        prices, which are likely to be higher than the current price charged by FES
        under the agreement and, as a result, Met-Ed’s and Penelec’s purchased power
        costs could materially increase.
  In
        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 is recommending that the Request for Proposal
        process cover the period of January 1, 2007 through May 31,
        2008.
        Under Pennsylvania's electric competition law, Penn is required to secure
        generation supply for customers who do not choose alternative suppliers for
        their electricity.
 
 **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 MTC rates. As of
        September 30, 2005, the accumulated deferred cost balance totaled
        approximately $508 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 of the
        securitization of the July 31, 2003 deferred balance. JCP&L is in
        discussions with the NJBPU staff as a result of the stipulated settlement
        agreements (as further discussed below) which recommended that the NJBPU
        issue
        an order regarding JCP&L's application. On July 20, 2005, JCP&L
        requested the NJBPU to set a procedural schedule for this matter and is awaiting
        NJBPU action.
 
 The
        2003 NJBPU
        decision on JCP&L's base electric rate proceeding (the Phase I Order)
        disallowed certain regulatory assets and provided for an interim return on
        equity of 9.5% on JCP&L's rate base. The Phase I order also provided for a
        Phase II proceeding in which the NJBPU would review whether JCP&L is in
        compliance with current service reliability and quality standards and determine
        whether the expenditures and projects undertaken by JCP&L to increase its
        system's reliability are prudent and reasonable for rate recovery. Depending
        on
        its assessment of JCP&L's service reliability, the NJBPU could have
        increased JCP&L’s return on equity to 9.75% or decreased it to 9.25%. On
        August 15, 2003 and June 1, 2004, JCP&L filed with the NJBPU an
        interim motion and a supplemental and amended motion for rehearing and
        reconsideration of the Phase I Order, respectively. On July 7, 2004,
        the
        NJBPU granted limited reconsideration and rehearing on the following issues:
        (1)
        deferred cost disallowances; (2) the capital structure including the rate
        of
        return; (3) merger savings, including amortization of costs to achieve merger
        savings; and (4) decommissioning costs.
 
 On
        July 16,
        2004, JCP&L filed the Phase II petition and testimony with the NJBPU,
        requesting an increase in base rates of $36 million for the recovery of system
        reliability costs and a 9.75% return on equity. The filing also requested
        an
        increase to the MTC deferred balance recovery of approximately $20 million
        annually.
  On
          May 25,
          2005, the NJBPU approved two stipulated settlement agreements. The first
          stipulation between JCP&L and the NJBPU staff resolves all of the issues
          associated with JCP&L's motion for reconsideration of the Phase I Order. The
          second stipulation between JCP&L, the NJBPU staff and the Ratepayer Advocate
          resolves all of the issues associated with JCP&L's Phase II proceeding. The
          stipulated settlements provide for, among other things, the
          following:


18




·
              An
                  annual
                  increase in distribution revenues of $23 million effective June 1,
                  2005, associated with the Phase I Order
                  reconsideration;
 
 ·
              An
                  annual
                  increase in distribution revenues of $36 million effective June 1,
                  2005, related to JCP&L's Phase II
                  Petition;
 
 ·
              An
                  annual
                  reduction in both rates and amortization expense of $8 million,
                  effective
                  June 1, 2005, in anticipation of an NJBPU order regarding
                  JCP&L's
                  request to securitize up to $277 million of its deferred cost
                  balance;
 
 ·
              An
                  increase
                  in JCP&L's authorized return on common equity from 9.5% to 9.75%;
                  and
 
 ·
              A
                  commitment
                  by JCP&L to maintain a target level of customer service reliability
                  with a reduction in JCP&L's authorized return on common equity from
                  9.75% to 9.5% if the target is not met for two consecutive quarters.
                  The
                  authorized return on common equity would then be restored to 9.75%
                  if the
                  target is met for two consecutive
                  quarters.
 
 The
        Phase II
        stipulation included an agreement that the distribution revenue increase
        also
        reflects a three-year amortization of JCP&L's one-time service reliability
        improvement costs incurred in 2003-2005. This resulted in the creation of
        a
        regulatory asset associated with accelerated tree trimming and other reliability
        costs which were expensed in 2003 and 2004. The establishment of the new
        regulatory asset of approximately $28 million resulted in an increase to
        net
        income of approximately $16 million ($0.05 per share of common stock) in
        the
        second quarter of 2005.
 
 JCP&L
        sells all
        self-supplied energy (NUGs and owned generation) to the wholesale market
        with
        offsetting credits to its deferred energy balance with the exception of 300
        MW
        from JCP&L's NUG committed supply currently being used to serve BGS
        customers pursuant to NJBPU order for the period June 1, 2005 through
        May 31, 2006. New BGS tariffs reflecting the results of a February
        2005
        auction for the BGS supply became effective June 1, 2005. On July 1,
        2005, JCP&L filed its BGS procurement proposals for post transition year
        four. The auction is scheduled to take place in February 2006 for the annual
        supply period beginning June 1, 2006.
 
 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 Ratepayer Advocate filed comments on
        February 28, 2005. On March 18, 2005, JCP&L filed a response to
        those comments. A schedule for further proceedings has not yet been
        set.
 
 **Transmission**
 
 On
        November 1,
        2004, ATSI requested authority from the FERC to defer approximately $54 million
        of vegetation management costs estimated to be incurred from 2004 through
        2007.
        On March 4, 2005, the FERC approved ATSI's request to defer those
        costs
        ($21 million deferred as of September 30, 2005). ATSI expects to file
        an
        application with the FERC in the second quarter of 2006 that would include
        recovery of the deferred costs.
 
 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 seeks 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 Ohio Companies reached a settlement with OCC, PUCO staff,
        Industrial Energy Users - Ohio and OPAE. The only other party in this
        proceeding, Dominion Retail, Inc., agreed not to oppose the settlement. This
        settlement, which was filed with the PUCO on July 22, 2005, provides
        for
        the rider recovery requested by the Ohio Companies, with carrying charges
        applied in the subsequent year’s rider for any over or under collection while
        the then-current rider is in effect. The PUCO approved the settlement
        stipulation on August 31, 2005. The incremental Transmission and Ancillary
        service revenues expected to be recovered from January through June 2006
        are
        approximately $61.2 million. This amount includes the recovery of
        the 2005
        deferred MISO expenses as described below. In May 2006, the Companies will
        file
        a modification to the rider to determine revenues from July 2006 through
        June
        2007.




19




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. An
        application filed with the PUCO to recover these deferred charges over a
        five-year period through the rider, beginning in 2006, was approved in the
        PUCO
        order issued on August 31, 2005 approving the stipulation referred
        to
        above. The OCC, OPAE and the Ohio Companies each filed applications for
        rehearing. The Ohio Companies sought authority to defer the transmission
        and
        ancillary service-related costs incurred during the period October 1,
        2003
        through December 29, 2004, while both OCC and OPAE sought to have
        the PUCO
        deny deferral of all costs. On
        July 6,
        2005, the PUCO denied the Ohio Companies' and OCC’s applications and, at the
        request of the Ohio Companies, struck as untimely OPAE’s application. The OCC
        filed a notice of appeal with the Ohio Supreme Court on August 31,
        2005. On
        September 30, 2005, in accordance with appellate procedure, the PUCO filed
        with
        the Ohio Supreme Court the record in this case. The Companies' brief will
        be due
        thirty days after the OCC files its brief, which, absent any time extensions,
        must be filed no later than November 9, 2005.
 
 On
        January 12,
        2005, Met-Ed and Penelec filed a request with the PPUC for deferral of
        transmission-related costs beginning January 1, 2005, estimated to
        be
        approximately $8 million per month. The
        OCA, OSBA, OTS,
        MEIUG, PICA, Allegheny Electric Cooperative and Pennsylvania Rural Electric
        Association have all intervened in the case. To date no hearing schedule
        has
        been established, and neither company has yet implemented deferral accounting
        for these costs.
 
 On
        January 31,
        2005, certain PJM transmission owners made three filings 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. Second, the
        FERC
        approved the proposed Schedule 12 rate harmonization. Third, the FERC accepted
        the proposed formula rate, subject to referral and hearing procedures. On
        June 30, 2005, the PJM transmission owners filed a request for rehearing
        of
        the May 31, 2005 order. The rate design and formula rate proceedings
        are
        currently being litigated before the FERC. The outcome of these cases cannot
        be
        predicted.
 
 **Regulatory
        Assets**
 
 The
        EUOC recognize,
        as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU have authorized
        for recovery from customers in future periods. Without such authorization,
        costs
        currently recorded as regulatory assets would have been charged to income
        as
        incurred. All regulatory assets are expected to be recovered from customers
        under the Companies' respective transition and regulatory plans. Based on
        those
        plans, the Companies continue to bill and collect cost-based rates for their
        transmission and distribution services, which remain regulated; accordingly,
        it
        is appropriate that the Companies continue the application of SFAS 71 to
        those
        operations.
 
 The
        Ohio Companies
        are deferring customer shopping incentives and interest costs as new regulatory
        assets in accordance with the transition and rate stabilization plans. Under
        the
        RSP, recovery of these regulatory assets (OE - $302 million, CEI - $402 million,
        TE - $122 million, as of September 30, 2005) would have begun through
        a
        surcharge rate equal to the RTC rate in effect only after the transition
        costs
        have been fully recovered. Under the proposed RCP, OE's and TE's recovery
        of the
        new regulatory assets would begin January 1, 2006 and expected to
        be
        completed by December 31, 2008. CEI's new regulatory asset recovery
        would
        still begin after full recovery of its transition costs (estimated as of
        mid-2009) and expected to be completed by December 31, 2010. Amortization
        of the new regulatory assets for each accounting period would equal the amount
        of the surcharge revenue recognized during that period.
 
 Regulatory
        transition costs as of September 30, 2005 for JCP&L and Met-Ed are
        approximately $2.4 billion and $0.6 billion, respectively. Deferral
        of
        above-market costs from power supplied by NUGs to JCP&L are approximately
        $1.4 billion and are being recovered through BGS and MTC revenues. Met-Ed
        has
        deferred above-market NUG costs totaling approximately $200 million. These
        costs
        are being recovered through CTC revenues. The regulatory asset for above-market
        NUG future obligations and the corresponding liability are adjusted to fair
        value at the end of each quarter. Recovery of the remaining regulatory
        transition costs is expected to continue under the provisions of the various
        regulatory proceedings in New Jersey and Pennsylvania.


20




**15
        - NEW
        ACCOUNTING STANDARDS AND INTERPRETATIONS**
 
 *FSP
        No. FAS
        13-1, "Accounting for Rental Costs Incurred during the Construction
        Period"*
  Issued
          in October 2005, FSP No.
          FAS 13-1 requires rental costs associated with ground or building operating
          leases that are incurred during a construction period to be recognized
          as
          rental expense. The effective date of the FSP guidance is the first reporting
          period beginning after December 15, 2005. FirstEnergy is currently evaluating
          this FSP and its impact on the financial statements.
 
 *EITF
        Issue
        04-13, "Accounting for Purchases and Sales of Inventory with the Same
        Counterparty"*
  In
        September 2005,
        the EITF reached a final consensus on Issue 04-13 concluding that two or
        more
        legally separate exchange transactions with the same counterparty should
        be
        combined and considered as a single arrangement for purposes of applying
        APB 29,
        when the transactions were entered into "in contemplation" of one another.
        If
        two transactions are combined and considered a single arrangement, the EITF
        reached a consensus that an exchange of inventory should be accounted for
        at
        fair value. Although electric power is not capable of being held in inventory,
        there is no substantive conceptual distinction between exchanges involving
        power
        and other storable inventory. Therefore, FirstEnergy will adopt this EITF
        effective for new arrangements entered into, or modifications or renewals
        of
        existing arrangements, in interim or annual periods beginning after March
        15,
        2006. See Note 2 for an example of FirstEnergy's application of this
        Issue.
 
 *EITF
                  Issue No. 05-6, "Determining the Amortization Period for Leasehold
                  Improvements Purchased after Lease Inception or Acquired in a Business
                  Combination"*
  In
        June 2005, the
        EITF reached a consensus on the application guidance for Issue 05-6. EITF
        05-6
        addresses the amortization period for leasehold improvements that were either
        acquired in a business combination or placed in service significantly after
        and
        not contemplated at or near the beginning of the initial lease term. For
        leasehold improvements acquired in a business combination, the amortization
        period is the shorter of the useful life of the assets or a term that includes
        required lease periods and renewals that are deemed to be reasonably assured
        at
        the date of acquisition. Leasehold improvements that are placed in service
        significantly after and not contemplated at or near the beginning of the
        lease
        term should be amortized over the shorter of the useful life of the assets
        or a
        term that includes required lease periods and renewals that are deemed to
        be
        reasonably assured at the date the leasehold improvements are purchased.
        This
        EITF was effective July 1, 2005 and is consistent with FirstEnergy's current
        accounting.
 
 *FIN
        47,
“Accounting for Conditional Asset Retirement Obligations - an interpretation
        of
        FASB Statement No. 143”*
 
 On
        March 30,
        2005, the FASB issued FIN 47 to clarify the scope and timing of liability
        recognition for conditional asset retirement obligations. Under this
        interpretation, companies are required to recognize a liability for the fair
        value of an asset retirement obligation that is conditional on a future event,
        if the fair value of the liability can be reasonably estimated. In instances
        where there is insufficient information to estimate the liability, the
        obligation is to be recognized in the first period in which sufficient
        information becomes available to estimate its fair value. If the fair value
        cannot be reasonably estimated, that fact and the reasons why must be disclosed.
        This Interpretation is effective for FirstEnergy in the fourth quarter of
        2005.
        FirstEnergy and the Companies are currently evaluating the effect this
        Interpretation will have on their financial statements.
 
 *SFAS
                  154
                  - “Accounting Changes and Error Corrections - a replacement of APB
                  Opinion
                  No. 20 and FASB Statement No.
                  3”*
 
 In
        May 2005, the
        FASB issued SFAS 154 to change the requirements for accounting and reporting
        a
        change in accounting principle. It applies to all voluntary changes in
        accounting principle and to changes required by an accounting pronouncement
        when
        that pronouncement does not include specific transition provisions. This
        Statement requires retrospective application to prior periods’ financial
        statements of changes in accounting principle, unless it is impracticable
        to
        determine either the period-specific effects or the cumulative effect of
        the
        change. In those instances, this Statement requires that the new accounting
        principle be applied to the balances of assets and liabilities as of the
        beginning of the earliest period for which retrospective application is
        practicable and that a corresponding adjustment be made to the opening balance
        of retained earnings (or other appropriate components of equity or net assets
        in
        the statement of financial position) for that period rather than being reported
        in the Consolidated Statements of Income. This Statement also requires that
        a
        change in depreciation, amortization, or depletion method for long-lived,
        nonfinancial assets be accounted for as a change in accounting estimate affected
        by a change in accounting principle. The provisions of this Statement are
        effective for accounting changes and corrections of errors made in fiscal
        years
        beginning after December 15, 2005. FirstEnergy and the Companies will
        adopt
        this Statement effective January 1, 2006.




21




*SFAS
                  153,
                  “Exchanges of Nonmonetary Assets - an amendment of APB Opinion No.
                  29”*
 
 In
        December 2004,
        the FASB issued SFAS 153 amending APB 29, which was based on the principle
        that
        nonmonetary assets should be measured based on the fair value of the assets
        exchanged. The guidance in APB 29 included certain exceptions to that principle.
        SFAS 153 eliminates the exception from fair value measurement for nonmonetary
        exchanges of similar productive assets and replaces it with an exception
        for
        exchanges that do not have commercial substance. This Statement specifies
        that a
        nonmonetary exchange has commercial substance if the future cash flows of
        the
        entity are expected to change significantly as a result of the exchange.
        The
        provisions of this Statement are effective January 1, 2006 for FirstEnergy.
        This FSP is not expected to have a material impact on FirstEnergy's financial
        statements.
 
 *SFAS
        123(R),
“Share-Based Payment”*
 
 In
        December 2004,
        the FASB issued SFAS 123(R), a revision to SFAS 123, which requires expensing
        stock options in the financial statements. Important to applying the new
        standard is understanding how to (1) measure the fair value of stock-based
        compensation awards and (2) recognize the related compensation cost for those
        awards. For an award to qualify for equity classification, it must meet certain
        criteria in SFAS 123(R). An award that does not meet those criteria will
        be
        classified as a liability and remeasured each period. SFAS 123(R) retains
        SFAS
        123's requirements on accounting for income tax effects of stock-based
        compensation. In April 2005, the SEC delayed the effective date of SFAS 123(R)
        to annual, rather than interim, periods that begin after June 15,
        2005. The
        SEC’s new rule results in a six-month deferral for companies with a fiscal year
        beginning January 1. Therefore, FirstEnergy will adopt this Statement
        effective January 1, 2006. FirstEnergy expects to adopt modified
        prospective application, without restatement of prior interim periods. Potential
        cumulative adjustments, if any, have not yet been determined. FirstEnergy
        uses
        the Black-Scholes option-pricing model to value options for disclosure purposes
        only and expects to apply this pricing model upon adoption of SFAS 123(R).
 
 *SFAS
        151,
“Inventory Costs - an amendment of ARB No. 43, Chapter 4”*
 
 In
        November 2004,
        the FASB issued SFAS 151 to clarify the accounting for abnormal amounts of
        idle
        facility expense, freight, handling costs and wasted material (spoilage).
        Previous guidance stated that in some circumstances these costs may be “so
        abnormal” that they would require treatment as current period costs. SFAS 151
        requires abnormal amounts for these items to always be recorded as current
        period costs. In addition, this Statement requires that allocation of fixed
        production overheads to the cost of conversion be based on the normal capacity
        of the production facilities. The provisions of this statement are effective
        for
        inventory costs incurred by FirstEnergy beginning January 1, 2006.
        FirstEnergy is currently evaluating this Standard and does not expect it
        to have
        a material impact on the financial statements.
 
 *FSP
        FAS 115-1,
        "The Meaning of Other-Than-Temporary Impairment and its Application to Certain
        Investments"*
 
 In
        September 2005,
        the FASB finalized and renamed EITF 03-1 and 03-1-a to FSP FAS 115-1. FSP
        FAS
        115-1 will (1) supersede Issue 03-1 and EITF topic No. D-44, "Recognition
        of
        Other Than Temporary Impairment upon the Planned Sale of a Security Whose
        Cost
        Exceeds Fair Value," (2) clarify that an investor should recognize an impairment
        loss no later than when the impairment is deemed other than temporary, even
        if a
        decision to sell has not been made, and (3) be effective for
        other-than-temporary impairment and analyses conducted in periods beginning
        after September 15, 2005. The FASB expects to issue this FSP in the
        fourth
        quarter of 2005, which would require prospective application with an effective
        date for reporting periods beginning after December 15, 2005. FirstEnergy
        is
        currently evaluating this FSP Issue and any impact on its
        investments.
 
 *FSP
        109-1,
“Application of FASB Statement No. 109, Accounting for Income Taxes, to the
        Tax
        Deduction and Qualified Production Activities Provided by the American Jobs
        Creation Act of 2004”*
  Issued
        in December
        2004, FSP 109-1 provides guidance related to the provision within the American
        Jobs Creation Act of 2004 (Act) that provides a tax deduction on qualified
        production activities. The Act includes a tax deduction of up to nine percent
        (when fully phased-in) of the lesser of (a) “qualified production activities
        income,” as defined in the Act, or (b) taxable income (after the deduction for
        the utilization of any net operating loss carryforwards). The FASB believes
        that
        the deduction should be accounted for as a special deduction in accordance
        with
        SFAS 109, “Accounting for Income Taxes", which is consistent with FirstEnergy's
        accounting.









22


**16
        -
        SEGMENT INFORMATION:**
 
 FirstEnergy
        has
        three reportable segments: regulated services, power supply management services
        and FSG. The aggregate “Other” segments do not individually meet the criteria to
        be considered a reportable segment. FirstEnergy's primary segment is its
        regulated services segment, whose operations include the regulated sale of
        electricity and distribution and transmission services by its eight EUOCs
        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 the generation facilities
        of OE,
        CEI, TE and Penn resulting from the deregulation of the Companies' electric
        generation business. “Other” consists of MYR (a construction service company),
        retail natural gas operations (recently sold - see Note 6) and
        telecommunications services. 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 and 2004, included
        generating units that were leased or whose output was sold to the power supply
        management services segment. The regulated services segment’s internal revenues
        represent the rental revenues for the generating unit leases.
 
 The
        power supply
        management services segment has responsibility for FirstEnergy’s generation
        operations. Its net income is primarily derived from all electric generation
        sales revenues, which consist of generation services to regulated franchise
        customers who have not chosen an alternative generation supplier, retail
        sales
        in deregulated markets and all domestic unregulated electricity sales in
        the
        retail and wholesale markets, less the related costs of electricity generation
        and sourcing of commodity requirements. Its net income also reflects the
        expense
        of the intersegment generating unit leases and power sales agreements discussed
        above and property taxes related to those generating units.
 
 Segment
        reporting
        for interim periods in 2004 have been reclassified to conform with the current
        year business segment organization and operations that were reported in the
        2004
        Form 10-K, emphasizing FirstEnergy's regulated electric businesses and power
        supply management operations and the reclassification of discontinued operations
        (see Note 6). FSG is being disclosed as a reporting segment due to its
        subsidiaries qualifying as held for sale (see Note 6 for discussion of the
        divestiture of three of those subsidiaries in 2005). Interest expense on
        holding
        company debt and corporate support services revenues and expenses are included
        in "Reconciling Items."








23





**Segment
                  Financial Information****Power****Supply****Regulated**
              
              **Management**
              
              **Facilities**
              
              
              
              **Reconciling****Services**
              
              **Services**
              
              **Services**
              
              **Other**
              
              **Adjustments**
              
              **Consolidated*****(In
                  millions)*****Three
                  Months Ended:****September
                  30, 2005**External
                  revenues
              
              $
              1,676
              
              $
              1,712
              
              $
              59
              
              $
              138
              
              $
              2
              
              $
              3,587Internal
                  revenues
              
              
              79
              
              
              -
              
              
              -
              
              
              -
              
              
              (79
              )
              
              -Total
                  revenues
              
              
              1,755
              
              
              1,712
              
              
              59
              
              
              138
              
              
              (77
              )
              
              3,587Depreciation
                  and amortization
              
              
              377
              
              
              9
              
              
              -
              
              
              1
              
              
              6
              
              
              393Net
                  interest
                  charges
              
              
              88
              
              
              11
              
              
              -
              
              
              2
              
              
              57
              
              
              158Income
                  taxes
              
              
              254
              
              
              7
              
              
              -
              
              
              4
              
              
              (28
              )
              
              237Income
                  before
                  discontinued operations
              
              
              366
              
              
              10
              
              
              (2
              )
              
              6
              
              
              (49
              )
              
              331Discontinued
                  operations
              
              
              -
              
              
              -
              
              
              -
              
              
              1
              
              
              -
              
              
              1Net
                  income
                  (loss)
              
              
              366
              
              
              10
              
              
              (2
              )
              
              7
              
              
              (49
              )
              
              332Total
                  assets
              
              
              28,385
              
              
              1,741
              
              
              82
              
              
              522
              
              
              644
              
              
              31,374Total
                  goodwill
              
              
              5,938
              
              
              24
              
              
              -
              
              
              62
              
              
              -
              
              
              6,024Property
                  additions
              
              
              207
              
              
              79
              
              
              -
              
              
              1
              
              
              7
              
              
              294**September
                  30, 2004**External
                  revenues
              
              $
              1,481
              
              $
              1,756
              
              $
              61
              
              $
              90
              
              $
              (3
              )
              $
              3,385Internal
                  revenues
              
              
              80
              
              
              -
              
              
              -
              
              
              -
              
              
              (80
              )
              
              -Total
                  revenues
              
              
              1,561
              
              
              1,756
              
              
              61
              
              
              90
              
              
              (83
              )
              
              3,385Depreciation
                  and amortization
              
              
              374
              
              
              9
              
              
              -
              
              
              -
              
              
              9
              
              
              392Net
                  interest
                  charges
              
              
              82
              
              
              9
              
              
              -
              
              
              -
              
              
              60
              
              
              151Income
                  taxes
              
              
              226
              
              
              30
              
              
              -
              
              
              (1
              )
              
              (41
              )
              
              214Income
                  before
                  discontinued operations
              
              
              315
              
              
              44
              
              
              -
              
              
              (2
              )
              
              (61
              )
              
              296Discontinued
                  operations
              
              
              -
              
              
              -
              
              
              1
              
              
              2
              
              
              -
              
              
              3Net
                  income
                  (loss)
              
              
              315
              
              
              44
              
              
              1
              
              
              -
              
              
              (61
              )
              
              299Total
                  assets
              
              
              28,416
              
              
              1,467
              
              
              182
              
              
              596
              
              
              564
              
              
              31,225Total
                  goodwill
              
              
              5,965
              
              
              24
              
              
              37
              
              
              75
              
              
              -
              
              
              6,101Property
                  additions
              
              
              157
              
              
              46
              
              
              -
              
              
              1
              
              
              7
              
              
              211


**Nine
                  Months Ended:****September
                  30, 2005**External
                  revenues
              
              $
              4,366
              
              $
              4,346
              
              $
              161
              
              $
              385
              
              $
              19
              
              $
              9,277Internal
                  revenues
              
              
              237
              
              
              -
              
              
              -
              
              
              -
              
              
              (237
              )
              
              -Total
                  revenues
              
              
              4,603
              
              
              4,346
              
              
              161
              
              
              385
              
              
              (218
              )
              
              9,277Depreciation
                  and amortization
              
              
              1,076
              
              
              26
              
              
              -
              
              
              2
              
              
              19
              
              
              1,123Net
                  interest
                  charges
              
              
              285
              
              
              29
              
              
              1
              
              
              4
              
              
              170
              
              
              489Income
                  taxes
              
              
              595
              
              
              (10
              )
              
              3
              
              
              13
              
              
              (2
              )
              
              599Income
                  before
                  discontinued operations
              
              
              856
              
              
              (15
              )
              
              (6
              )
              
              18
              
              
              (201
              )
              
              652Discontinued
                  operations
              
              
              -
              
              
              -
              
              
              13
              
              
              5
              
              
              -
              
              
              18Net
                  income
                  (loss)
              
              
              856
              
              
              (15
              )
              
              7
              
              
              23
              
              
              (201
              )
              
              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**September
                  30, 2004**External
                  revenues
              
              $
              4,049
              
              $
              4,828
              
              $
              156
              
              $
              324
              
              $
              4
              
              $
              9,361Internal
                  revenues
              
              
              239
              
              
              -
              
              
              -
              
              
              -
              
              
              (239
              )
              
              -Total
                  revenues
              
              
              4,288
              
              
              4,828
              
              
              156
              
              
              324
              
              
              (235
              )
              
              9,361Depreciation
                  and amortization
              
              
              1,098
              
              
              26
              
              
              1
              
              
              -
              
              
              28
              
              
              1,153Net
                  interest
                  charges
              
              
              301
              
              
              30
              
              
              -
              
              
              2
              
              
              169
              
              
              502Income
                  taxes
              
              
              541
              
              
              55
              
              
              (1
              )
              
              (19
              )
              
              (70
              )
              
              506Income
                  before
                  discontinued operations
              
              
              761
              
              
              79
              
              
              (1
              )
              
              39
              
              
              (207
              )
              
              671Discontinued
                  operations
              
              
              -
              
              
              -
              
              
              3
              
              
              3
              
              
              -
              
              
              6Net
                  income
                  (loss)
              
              
              761
              
              
              79
              
              
              2
              
              
              42
              
              
              (207
              )
              
              677Total
                  assets
              
              
              28,416
              
              
              1,467
              
              
              182
              
              
              596
              
              
              564
              
              
              31,225Total
                  goodwill
              
              
              5,965
              
              
              24
              
              
              37
              
              
              75
              
              
              -
              
              
              6,101Property
                  additions
              
              
              377
              
              
              149
              
              
              2
              
              
              1
              
              
              17
              
              
              546Reconciling
                  adjustments to segment operating results from internal management
                  reporting to consolidated external financial reporting primarilyconsist
                  of
                  interest expense related to holding company debt, corporate support
                  services revenues and expenses, fuel marketing revenues, which
                  arereflected
                  as
                  reductions to expenses for internal management reporting purposes,
                  and
                  elimination of intersegment transactions.






24


**17
        -
        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.
        When fully completed, the asset transfers will result in the respective
        undivided ownership interests of the Ohio Companies and Penn in FirstEnergy’s
        nuclear and non-nuclear plants being owned by NGC, and FGCO, respectively.
        The
        generating plant interests that are being 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 the May 13, and May 18, 2005 agreements
        and FGCO's purchase option under the Master Facility Lease.
 
 As
        contemplated by
        the agreements entered into in May 2005, the Ohio Companies and Penn intend
        to
        transfer their respective interests in the nuclear generation assets to NGC
        through, in the case of OE and Penn, a spin-off by way of dividend and, in
        the
        case of CEI and TE, a sale at net book value. FENOC currently operates and
        maintains the nuclear generation assets to be transferred. FirstEnergy currently
        expects to complete the nuclear asset transfers in the fourth quarter of
        2005,
        subject to the receipt of required regulatory approvals.
 
 These
        transactions
        are 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 will essentially complete the divestitures contemplated by the
        restructuring plans by transferring the ownership interests to NGC and FGCO
        without impacting the operation of the plants.
 
 The
        following table
        provides the value of assets pending sale along with the related liabilities
        as
        of September 30, 2005:





**OE**
            
            **Penn**
            
            **CEI**
            
            **TE*****(In
                millions)*****Assets
                Pending Sale**Property,
                plant and equipment
            
            $
            1,598
            
            $
            440
            
            $
            1,305
            
            $
            687Other
                property and investments
            
            
            363
            
            
            147
            
            
            433
            
            
            276Current
                assets
            
            
            93
            
            
            38
            
            
            73
            
            
            42Deferred
                charges
            
            
            (60
            )
            
            2
            
            
            -
            
            
            -Total
            
            $
            1,994
            
            $
            627
            
            $
            1,811
            
            $
            1,005**Liabilities
                Related to Assets****Pending
                Sale**Long-term
                debt
            
            $
            238
            
            $
            53
            
            $
            **-**
            
            $
            **-**Current
                liabilities
            
            
            40
            
            
            31
            
            
            434
            
            
            253Noncurrent
                liabilities
            
            
            280
            
            
            226
            
            
            362
            
            
            202Total
            
            $
            558
            
            $
            310
            
            $
            796
            
            $
            455**Net
                Assets Pending Sale**
            
            $
            1,436
            
            $
            317
            
            $
            1,015
            
            $
            550














25





**FIRSTENERGY
                  CORP.****CONSOLIDATED
                  STATEMENTS OF INCOME****(Unaudited)****Three
                  Months Ended**
              
              **Nine
                  Months Ended****September
                  30,**
              
              **September
                  30,****2005**
              
              **2004**
              
              **2005**
              
              **2004*****(In
                  thousands, except per share amounts)*****REVENUES:**Electric
                  utilities
              
              $
              2,935,547
              
              $
              2,526,971
              
              $
              7,573,858
              
              $
              6,874,574Unregulated
                  businesses (Note 2)
              
              
              651,240
              
              
              858,497
              
              
              1,703,281
              
              
              2,485,959Total
                  revenues
              
              
              3,586,787
              
              
              3,385,468
              
              
              9,277,139
              
              
              9,360,533**EXPENSES:**Fuel
                  and
                  purchased power (Note 2)
              
              
              1,287,225
              
              
              1,285,355
              
              
              3,115,153
              
              
              3,514,816Other
                  operating expenses
              
              
              992,436
              
              
              868,440
              
              
              2,758,378
              
              
              2,500,182Provision
                  for
                  depreciation
              
              
              152,786
              
              
              147,052
              
              
              444,443
              
              
              439,017Amortization
                  of regulatory assets
              
              
              364,337
              
              
              324,300
              
              
              981,750
              
              
              905,488Deferral
                  of
                  new regulatory assets
              
              
              (123,827
              )
              
              (78,767
              )
              
              (303,496
              )
              
              (191,487
              )General
                  taxes
              
              
              187,562
              
              
              177,452
              
              
              540,606
              
              
              514,174Total
                  expenses
              
              
              2,860,519
              
              
              2,723,832
              
              
              7,536,834
              
              
              7,682,190**INCOME
                  BEFORE INTEREST AND INCOME TAXES**
              
              
              726,268
              
              
              661,636
              
              
              1,740,305
              
              
              1,678,343**NET
                  INTEREST CHARGES:**Interest
                  expense
              
              
              162,104
              
              
              152,348
              
              
              488,462
              
              
              504,396Capitalized
                  interest
              
              
              (7,005
              )
              
              (6,536
              )
              
              (11,957
              )
              
              (18,286
              )Subsidiaries’
                  preferred stock dividends
              
              
              2,626
              
              
              5,354
              
              
              12,912
              
              
              16,024Net
                  interest
                  charges
              
              
              157,725
              
              
              151,166
              
              
              489,417
              
              
              502,134**INCOME
                  TAXES**
              
              
              236,711
              
              
              214,345
              
              
              599,261
              
              
              505,875**INCOME
                  BEFORE DISCONTINUED OPERATIONS**
              
              
              331,832
              
              
              296,125
              
              
              651,627
              
              
              670,334Discontinued
                  operations (net of income taxes (benefit) of$367,000
                  and
                  $1,625,000 in the three months endedSeptember
                  30,
                  and ($8,684,000) and $3,762,000 in the ninemonths
                  ended
                  September 30, of 2005 and 2004, respectively)(Note
                  6)
              
              
              528
              
              
              2,497
              
              
              18,451
              
              
              6,332**NET
                  INCOME**
              
              $
              332,360
              
              $
              298,622
              
              $
              670,078
              
              $
              676,666**BASIC
                  EARNINGS PER SHARE OF COMMON STOCK:**Earnings
                  before discontinued operations
              
              $
              1.01
              
              $
              0.90
              
              $
              1.99
              
              $
              2.05Discontinued
                  operations (Note 6)
              
              
              -
              
              
              0.01
              
              
              0.05
              
              
              0.02Net
                  earnings
                  per basic share
              
              $
              1.01
              
              $
              0.91
              
              $
              2.04
              
              $
              2.07**WEIGHTED
                  AVERAGE NUMBER OF BASIC SHARES****OUTSTANDING**
              
              
              328,119
              
              
              327,499
              
              
              328,030
              
              
              327,280**DILUTED
                  EARNINGS PER SHARE OF COMMON STOCK:**Earnings
                  before discontinued operations
              
              $
              1.01
              
              $
              0.90
              
              $
              1.98
              
              $
              2.04Discontinued
                  operations (Note 6)
              
              
              -
              
              
              0.01
              
              
              0.05
              
              
              0.02Net
                  earnings
                  per diluted share
              
              $
              1.01
              
              $
              0.91
              
              $
              2.03
              
              $
              2.06**WEIGHTED
                  AVERAGE NUMBER OF DILUTED SHARES****OUTSTANDING**
              
              
              330,193
              
              
              329,099
              
              
              329,926
              
              
              328,850**DIVIDENDS
                  DECLARED PER SHARE OF COMMON STOCK**
              
              $
              0.43
              
              $
              0.375
              
              $
              1.255
              
              $
              1.125The
                  preceding
                  Notes to Consolidated Financial Statements as they relate to FirstEnergy
                  Corp. are an integral part of these statements.
    26






**FIRSTENERGY
                  CORP.****CONSOLIDATED
                  STATEMENTS OF COMPREHENSIVE INCOME****(Unaudited)****Three
                  Months Ended**
              
              **Nine
                  Months Ended****September
                  30,**
              
              **September
                  30,****2005**
              
              **2004**
              
              **2005**
              
              **2004*****(In
                  thousands)*****NET
                  INCOME**
              
              $
              332,360
              
              $
              298,622
              
              $
              670,078
              
              $
              676,666**OTHER
                  COMPREHENSIVE INCOME (LOSS):**Unrealized
                  gain on derivative hedges
              
              
              17,723
              
              
              5,927
              
              
              19,023
              
              
              26,536Unrealized
                  gain (loss) on available for sale securities
              
              
              (13,093
              )
              
              8,715
              
              
              (37,216
              )
              
              5,265Other
                  comprehensive income (loss)
              
              
              4,630
              
              
              14,642
              
              
              (18,193
              )
              
              31,801Income
                  tax
                  expense (benefit) related to othercomprehensive
                  income
              
              
              (1,797
              )
              
              2,498
              
              
              (7,704
              )
              
              11,026Other
                  comprehensive income (loss), net of tax
              
              
              6,427
              
              
              12,144
              
              
              (10,489
              )
              
              20,775**COMPREHENSIVE
                  INCOME**
              
              $
              338,787
              
              $
              310,766
              
              $
              659,589
              
              $
              697,441The
                  preceding
                  Notes to Consolidated Financial Statements as they relate to FirstEnergy
                  Corp. are an integral part of thesestatements.








27




**FIRSTENERGY
                  CORP.****CONSOLIDATED
                  BALANCE SHEETS****(Unaudited)****September
                  30,**
              
              **December
                  31,****2005**
              
              **2004*****(In
                  thousands)*****ASSETS****CURRENT
                  ASSETS:**Cash
                  and cash
                  equivalents
              
              $
              139,812
              
              $
              52,941Receivables
                  -Customers
                  (less accumulated provisions of $37,429,000 and$34,476,000,
                  respectively, for uncollectible accounts)
              
              
              1,336,969
              
              
              979,242Other
                  (less
                  accumulated provisions of $26,416,000 and$26,070,000,
                  respectively, for uncollectible accounts)
              
              
              198,256
              
              
              377,195Materials
                  and
                  supplies, at average cost -Owned
              
              
              378,937
              
              
              363,547Under
                  consignment
              
              
              117,265
              
              
              94,226Prepayments
                  and other
              
              
              235,496
              
              
              145,1962,406,735
              
              
              2,012,347**PROPERTY,
                  PLANT AND EQUIPMENT:**In
                  service
              
              
              22,777,299
              
              
              22,213,218Less
                  -
                  Accumulated provision for depreciation
              
              
              9,688,122
              
              
              9,413,73013,089,177
              
              
              12,799,488Construction
                  work in progress
              
              
              684,042
              
              
              678,86813,773,219
              
              
              13,478,356**INVESTMENTS:**Nuclear
                  plant
                  decommissioning trusts
              
              
              1,711,112
              
              
              1,582,588Investments
                  in
                  lease obligation bonds
              
              
              905,504
              
              
              951,352Other
              
              
              773,994
              
              
              740,0263,390,610
              
              
              3,273,966**DEFERRED
                  CHARGES:**Goodwill
              
              
              6,024,376
              
              
              6,050,277Regulatory
                  assets
              
              
              5,045,838
              
              
              5,532,087Other
              
              
              733,164
              
              
              720,91111,803,378
              
              
              12,303,275$
              31,373,942
              
              $
              31,067,944**LIABILITIES
                  AND CAPITALIZATION****CURRENT
                  LIABILITIES:**Currently
                  payable long-term debt
              
              $
              983,412
              
              $
              940,944Short-term
                  borrowings
              
              
              246,505
              
              
              170,489Accounts
                  payable
              
              
              651,941
              
              
              610,589Accrued
                  taxes
              
              
              852,477
              
              
              657,219Other
              
              
              1,110,511
              
              
              929,1943,844,846
              
              
              3,308,435**CAPITALIZATION:**Common
                  stockholders’ equity -Common
                  stock,
                  $0.10 par value, authorized 375,000,000 shares -329,836,276
                  shares outstanding
              
              
              32,984
              
              
              32,984Other
                  paid-in
                  capital
              
              
              7,033,726
              
              
              7,055,676Accumulated
                  other comprehensive loss
              
              
              (323,601
              )
              
              (313,112
              )Retained
                  earnings
              
              
              2,115,434
              
              
              1,856,863Unallocated
                  employee stock ownership plan common stock -1,642,223
                  and
                  2,032,800 shares, respectively
              
              
              (30,584
              )
              
              (43,117
              )Total
                  common stockholders' equity
              
              
              8,827,959
              
              
              8,589,294Preferred
                  stock of consolidated subsidiaries
              
              
              183,719
              
              
              335,123Long-term
                  debt
                  and other long-term obligations
              
              
              9,418,734
              
              
              10,013,34918,430,412
              
              
              18,937,766**NONCURRENT
                  LIABILITIES:**Accumulated
                  deferred income taxes
              
              
              2,345,281
              
              
              2,324,097Asset
                  retirement obligations
              
              
              1,130,194
              
              
              1,077,557Power
                  purchase
                  contract loss liability
              
              
              1,920,358
              
              
              2,001,006Retirement
                  benefits
              
              
              1,343,461
              
              
              1,238,973Lease
                  market
                  valuation liability
              
              
              872,650
              
              
              936,200Other
              
              
              1,486,740
              
              
              1,243,9109,098,684
              
              
              8,821,743**COMMITMENTS,
                  GUARANTEES AND CONTINGENCIES (Note 13)**$
              31,373,942
              
              $
              31,067,944The
                  preceding
                  Notes to Consolidated Financial Statements as they relate to FirstEnergy
                  Corp. are an integral part of thesebalance
                  sheets.
    28




**FIRSTENERGY
                  CORP.****CONSOLIDATED
                  STATEMENTS OF CASH FLOWS****(Unaudited)****Three
                  Months Ended**
              
              **Nine
                  Months Ended****September
                  30,**
              
              **September
                  30,****2005**
              
              **2004**
              
              **2005**
              
              **2004*****(In
                  thousands)*****CASH
                  FLOWS FROM OPERATING ACTIVITIES:**Net
                  income
              
              $
              332,360
              
              $
              298,622
              
              $
              670,078
              
              $
              676,666Adjustments
                  to reconcile net income to net cash fromoperating
                  activities -Provision
                  for
                  depreciation
              
              
              152,786
              
              
              147,052
              
              
              444,443
              
              
              439,017Amortization
                  of regulatory assets
              
              
              364,337
              
              
              324,300
              
              
              981,750
              
              
              905,488Deferral
                  of
                  new regulatory assets
              
              
              (123,827
              )
              
              (78,767
              )
              
              (303,496
              )
              
              (191,487
              )Nuclear
                  fuel
                  and lease amortization
              
              
              25,785
              
              
              26,776
              
              
              63,363
              
              
              71,782Amortization
                  of electric service obligation
              
              
              (8,630
              )
              
              (3,336
              )
              
              (24,135
              )
              
              (12,877
              )Deferred
                  purchased power and other costs
              
              
              (39,215
              )
              
              (118,409
              )
              
              (231,438
              )
              
              (263,290
              )Deferred
                  income taxes and investment tax credits, net
              
              
              (37,851
              )
              
              37,138
              
              
              24,034
              
              
              (56,995
              )Deferred
                  rents and lease market valuation liability
              
              
              29,834
              
              
              28,402
              
              
              (71,275
              )
              
              (52,182
              )Accrued
                  retirement benefit obligations
              
              
              56,116
              
              
              42,397
              
              
              104,488
              
              
              106,897Accrued
                  compensation, net
              
              
              4,380
              
              
              25,864
              
              
              (32,895
              )
              
              48,186Commodity
                  derivative transactions, net
              
              
              (55,101
              )
              
              17,336
              
              
              (40,993
              )
              
              (37,443
              )Cash
                  collateral from suppliers
              
              
              76,978
              
              
              -
              
              
              76,978
              
              
              -Income
                  from
                  discontinued operations (Note 6)
              
              
              (528
              )
              
              (2,497
              )
              
              (18,451
              )
              
              (6,332
              )Pension
                  trust
                  contribution
              
              
              -
              
              
              (500,000
              )
              
              -
              
              
              (500,000
              )Decrease
                  (increase) in operating assets -Receivables
              
              
              (90,673
              )
              
              16,288
              
              
              (225,982
              )
              
              187,730Materials
                  and
                  supplies
              
              
              11,976
              
              
              6,210
              
              
              (39,876
              )
              
              7,173Prepayments
                  and other current assets
              
              
              102,025
              
              
              46,969
              
              
              (57,192
              )
              
              (42,625
              )Increase
                  (decrease) in operating liabilities -Accounts
                  payable
              
              
              (44,369
              )
              
              (37,049
              )
              
              59,662
              
              
              (145,691
              )Accrued
                  taxes
              
              
              167,851
              
              
              152,009
              
              
              207,006
              
              
              296,668Accrued
                  interest
              
              
              95,721
              
              
              82,221
              
              
              91,934
              
              
              75,158Prepayment
                  for electric service - education programs
              
              
              -
              
              
              -
              
              
              241,685
              
              
              -Other
              
              
              (38,799
              )
              
              15,979
              
              
              (7,416
              )
              
              32,370Net
                  cash
                  provided from operating activities
              
              
              981,156
              
              
              527,505
              
              
              1,912,272
              
              
              1,538,213**CASH
                  FLOWS FROM FINANCING ACTIVITIES:**New
                  Financing
                  -Long-term
                  debt
              
              
              88,950
              
              
              86,754
              
              
              334,300
              
              
              961,474Short-term
                  borrowings, net
              
              
              -
              
              
              228,072
              
              
              77,295
              
              
              -Redemptions
                  and Repayments -Preferred
                  stock
              
              
              (30,000
              )
              
              (1,000
              )
              
              (169,650
              )
              
              (1,000
              )Long-term
                  debt
              
              
              (162,939
              )
              
              (772,451
              )
              
              (851,687
              )
              
              (1,752,394
              )Short-term
                  borrowings, net
              
              
              (308,319
              )
              
              -
              
              
              -
              
              
              (219,032
              )Net
                  controlled disbursement activity
              
              
              (27,118
              )
              
              (19,129
              )
              
              (27,594
              )
              
              (36,400
              )Common
                  stock
                  dividend payments
              
              
              (141,023
              )
              
              (123,965
              )
              
              (411,507
              )
              
              (367,751
              )Net
                  cash used
                  for financing activities
              
              
              (580,449
              )
              
              (601,719
              )
              
              (1,048,843
              )
              
              (1,415,103
              )**CASH
                  FLOWS FROM INVESTING ACTIVITIES:**Property
                  additions
              
              
              (294,443
              )
              
              (211,243
              )
              
              (756,118
              )
              
              (545,743
              )Proceeds
                  from
                  asset sales
              
              
              -
              
              
              1,662
              
              
              61,207
              
              
              213,109Proceeds
                  from
                  certificates of deposit
              
              
              -
              
              
              277,763
              
              
              -
              
              
              277,763Nonutility
                  generation trust contributions
              
              
              -
              
              
              -
              
              
              -
              
              
              (50,614
              )Contributions
                  to nuclear decommissioning trusts
              
              
              (25,370
              )
              
              (25,370
              )
              
              (76,112
              )
              
              (76,112
              )Cash
                  investments
              
              
              (13,950
              )
              
              (7,316
              )
              
              21,171
              
              
              19,640Other
              
              
              23,120
              
              
              7,072
              
              
              (26,706
              )
              
              (7,236
              )Net
                  cash
                  provided from (used for) investing activities
              
              
              (310,643
              )
              
              42,568
              
              
              (776,558
              )
              
              (169,193
              )Net
                  change in
                  cash and cash equivalents
              
              
              90,064
              
              
              (31,646
              )
              
              86,871
              
              
              (46,083
              )Cash
                  and cash
                  equivalents at beginning of period
              
              
              49,748
              
              
              99,538
              
              
              52,941
              
              
              113,975Cash
                  and cash
                  equivalents at end of period
              
              $
              139,812
              
              $
              67,892
              
              $
              139,812
              
              $
              67,892The
                  preceding
                  Notes to Consolidated Financial Statements as they relate to FirstEnergy
                  Corp. are an integral part of thesestatements.






29
 ***Report
          of Independent Registered Public Accounting Firm***
 
 
 
 
 
 
 
 
 
 To
          the 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, 2005, and the related consolidated statements
          of income, comprehensive income and cash flows for each of the three-month
          and
          nine-month periods ended September 30, 2005 and 2004. 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
          previously
          audited, in accordance with the standards of the Public Company Accounting
          Oversight Board (United States), the consolidated balance sheet as of
          December 31, 2004, 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,
          2004 and the effectiveness of the Company’s internal control over financial
          reporting as of December 31, 2004; 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(K) 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 March 7, 2005, 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 information as of December 31,
          2004, is fairly stated in all material respects in relation to the consolidated
          balance sheet from which it has been derived.
 
 
 
 
 PricewaterhouseCoopers
          LLP
 Cleveland,
          Ohio
 November
          1,
          2005




30





**FIRSTENERGY
        CORP.**
 
 **MANAGEMENT’S
        DISCUSSION AND ANALYSIS OF**
 **RESULTS
        OF
        OPERATIONS AND FINANCIAL CONDITION**
 
 
 **EXECUTIVE
        SUMMARY**
    Net
        income in the
        third quarter of 2005 was $332 million, or basic and diluted earnings of
        $1.01
        per share of common stock, compared to net income of $299 million, or basic
        and
        diluted earnings of $0.91 per share of common stock for the third quarter
        of
        2004. Net income in the first nine months of 2005 was $670 million, or basic
        earnings of $2.04 per share of common stock ($2.03 diluted) compared to $677
        million in the first nine months of 2004, or basic earnings of $2.07 per
        share
        of common stock ($2.06 diluted). The following Non-GAAP Reconciliation displays
        the unusual items resulting in the difference between GAAP and non-GAAP
        earnings.


**Reconciliation
                of non-GAAP to GAAP**
            
            **2005**
            
            **2004****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)
            
            $
            342
            
            $
            1.04
            
            $
            319
            
            $
            0.97Unusual
                Items:Non-core
                asset sales gains/losses, net
            
            
            -
            
            
            -
            
            
            (16
            )
            
            (0.05
            )JCP&L
                arbitration decision
            
            
            (10
            )
            
            (0.03
            )
            
            -
            
            
            -Other
            
            
            -
            
            
            -
            
            
            (4
            )
            
            (0.01
            )Net
                Income
                (GAAP)
            
            $
            332
            
            $
            1.01
            
            $
            299
            
            $
            0.91**Nine
                Months Ended September 30,**Earnings
                Before Unusual Items (Non-GAAP)
            
            $
            730
            
            $
            2.22
            
            $
            753
            
            $
            2.30Unusual
                Items:Non-core
                asset sales gains/losses, net
            
            
            22
            
            
            0.07
            
            
            (23
            )
            
            (0.07
            )Davis-Besse
                impacts
            
            
            -
            
            
            -
            
            
            (38
            )
            
            (0.12
            )EPA
                settlement
            
            
            (14
            )
            
            (0.04
            )
            
            -
            
            
            -NRC
                fine
            
            
            (3
            )
            
            (0.01
            )
            
            -
            
            
            -JCP&L
                rate settlement
            
            
            16
            
            
            0.05
            
            
            -
            
            
            -JCP&L
                arbitration decision
            
            
            (10
            )
            
            (0.03
            )
            
            -
            
            
            -Ohio
                tax write-off
            
            
            (71
            )
            
            (0.22
            )
            
            -
            
            
            -Class-action
                lawsuit settlement
            
            
            -
            
            
            -
            
            
            (11
            )
            
            (0.03
            )Other
            
            
            -
            
            
            -
            
            
            (4
            )
            
            (0.01
            )Net
                Income
                (GAAP)
            
            $
            670
            
            $
            2.04
            
            $
            677
            
            $
            2.07




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
          management 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 item refers to a finite
          set
          of energy-related assets that have been previously disclosed as held for
          sale, a
          substantial portion of which has already been sold. In addition, as Davis-Besse
          restarted in 2004, further impacts from its extended outage are not expected.
          Similarly, further litigation settlements similar to the class action
          settlements in 2004 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
          its businesses, over the longer term and assists investors in comparing
          FirstEnergy’s operating performance to the operating performance of others in
          the energy sector.
 
 On
          October 3,
          2005, S&P raised its corporate credit rating on FirstEnergy and the EUOC to
          'BBB' from 'BBB-'. At the same time, S&P raised the senior unsecured ratings
          at the holding company to 'BBB-' from 'BB+' and each of the EUOC by one
          notch
          above the previous rating. S&P noted that the upgrade followed the
          continuation of a good operating track record, specifically for the nuclear
          fleet through the third quarter of 2005. S&P also stated that FirstEnergy’s
          rating reflects the benefits of supportive regulation, low-cost base load
          generation fleet, low-risk transmission and distribution operations and
          rate
          certainty in Ohio. FirstEnergy’s ability to consistently generate free cash
          flow, good liquidity, and an improving financial profile were also noted
          as
          strengths.




31




On
        September 20,
        2005, FirstEnergy raised its quarterly dividend to $0.43 per share of
        outstanding common stock - 4.2% higher than the previous quarterly rate of
        $0.4125 per share. This action represents the second dividend payment increase
        this year. The dividend payment was last increased by 10% for the dividend
        paid
        on March 1, 2005. The new dividend is payable December 1, 2005
        to
        shareholders of record on November 7, 2005. The Company’s dividend policy,
        established on November 30, 2004, targets sustainable annual dividend
        increases after 2005, generally reflecting an annual growth rate of 4% to
        5%,
        and an earnings payout ratio generally within the range of 50% to 60%. The
        Board
        of Directors will continue to review the Company's dividend policy regularly.
        The amount and timing of all dividend payments are subject to the Board's
        consideration of business conditions, results of operations, financial condition
        and other factors.
 
 On
        September 9,
        2005, FirstEnergy filed on behalf of the Ohio Companies an RCP that, if approved
        by the PUCO, would essentially maintain current electricity prices through
        2008.
        The RCP was developed as a result of concerns about potential impacts to
        customer rates due to rising fuel prices and other factors. A stipulated
        agreement in support of the plan has been signed by the cities of Cleveland
        and
        Akron, along with the Industrial Energy Users - Ohio and the Ohio Energy
        Group.
        Also, the Mayor of the City of Parma has agreed to support the stipulation.
        The
        Parma City Council passed a resolution in support of the RCP plan on September
        19, 2005.
  During
          the third
          quarter of 2005, several FirstEnergy operating companies reached employment
          agreements with various local unions. On July 13, 2005, UWUA 118
          and 126 -
          representing 445 workers - ratified an agreement with OE. On August 17,
          2005, UWUA Local 180 - representing 170 workers - ratified an agreement
          with
          Penelec. On August 25, 2005, IBEW Local 1194 - representing 240
          employees -
          ratified an agreement with OE. The collective bargaining agreement with
          IBEW
          Local 29 representing approximately 450 workers at the Beaver Valley Nuclear
          Power Station expired pursuant to its terms on September 30, 2005. The
          parties
          are currently negotiating a new agreement.
 On
        September 14, 2005, FENOC announced that it would pay the $5.45 million
        fine proposed in April 2005 by the NRC related to the reactor head issue
        at the
        Davis-Besse Nuclear Power Station. FirstEnergy accrued $2.0 million of the
        fine
        in 2004 and the remaining amount in the first quarter of 2005. In a letter
        to
        the NRC, the Company noted that paying the fine brings regulatory closure
        to
        this issue and enables it to continue focusing on safe, reliable plant
        operations. The letter also reiterated that FENOC acknowledges full
        responsibility for the significant performance deficiencies that led to the
        reactor head issue, and that the NRC has indicated that the cited violations
        regarding the past plant operations do not represent current
        performance.
 
 FirstEnergy
        announced on September 22, 2005, that FGCO plans to install an
        Electro-Catalytic Oxidation (ECO) system on the 215-megawatt Unit 4 of its
        Bay
        Shore Plant in Oregon, Ohio. ECO is a multipollutant-control technology for
        coal-based electric utility plants that was developed by Powerspan Corp.,
        a
        clean energy technology company in which FirstEnergy has a minority ownership
        interest.
 
 ECO
        is currently
        being demonstrated at FGCO's R. E. Burger Plant, and has proven effective
        in
        reducing NOx, SO 2 ,
        mercury, acid
        gases, and fine particulates (soot). The ECO process also produces a highly
        marketable ammonium sulfate fertilizer co-product, currently being sold to
        the
        fertilizer market.
 
 FGCO
        expects design
        engineering of the Bay Shore ECO system to commence in the first quarter
        of
        2006, and estimates the overall cost of the system, including a fertilizer
        processing plant, to be approximately $100 million.
 
 **FIRSTENERGY’S
        BUSINESS**
 
 FirstEnergy
        is a
        registered public utility holding company headquartered in Akron, Ohio that
        operates primarily through two core business segments.
 
 ·
              **Regulated
                  Services**transmits,
                  distributes and sells electricity through 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 primarily derives its revenue from the delivery of electricity,
                  including transition cost recovery.




32







·
            **Power
                Supply Management****Services**supplies the
                electric power needs of end-use customers (principally in Ohio,
                Pennsylvania and New Jersey) through retail and wholesale arrangements,
                including sales to meet the PLR requirements of FirstEnergy’s Ohio
                Companies and Penn. This business segment operates FirstEnergy's
                generating facilities and purchases from the wholesale market to
                meet its
                sales obligations. Pursuant to an asset transfer on October 24,
                2005,
                it now owns as well as operates FirstEnergy's fossil and hydroelectric
                generation facilities previously owned by the EUOC. It also purchases
                the
                entire output of the nuclear plants currently owned or leased by
                the EUOC.
                This business segment principally derives its revenues from electric
                generation sales.





Other
      operating
      segments provide a wide range of 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 non-core businesses. See Note 6 to the
      consolidated financial statements. The assets and revenues for the other
      business operations are below the quantifiable threshold for operating segments
      for separate disclosure as “reportable segments”.





**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.
      When fully completed, the asset transfers will result in the respective
      undivided ownership interests of the Ohio Companies and Penn in FirstEnergy’s
      nuclear and non-nuclear plants being owned by NGC, and FGCO, respectively.
      The
      generating plant interests that are being 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 the May 13 and May 18, 2005 agreements
      and FGCO's purchase option under the Master Facility Lease.





As
      contemplated by
      the agreements entered into in May 2005, the Ohio Companies and Penn intend
      to
      transfer their respective interests in the nuclear generation assets to NGC
      through, in the case of OE and Penn, a spin-off by way of dividend and, in
      the
      case of CEI and TE, a sale at net book value. FENOC currently operates and
      maintains the nuclear generation assets to be transferred. FirstEnergy currently
      expects to complete the nuclear asset transfers in the fourth quarter of 2005,
      subject to the receipt of required regulatory approvals.





These
      transactions
      are 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 will essentially complete the divestitures contemplated by the
      restructuring plans by transferring the ownership interests to NGC and FGCO
      without impacting the operation of the plants.





See
      Note 17 for
      disclosure of the assets held for sale by the Ohio Companies and Penn as of
      September 30, 2005.





33




**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 16 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 16 to the
        consolidated financial statements. Net income (loss) by major business segment
        is as follows:





**Three
                Months Ended**
            
            
            **Nine
                Months Ended****September
                30,**
            
            **Increase**
            
            **September
                30,**
            
            **Increase****2005**
            
            **2004**
            
            **(Decrease)**
            
            **2005**
            
            **2004**
            
            **(Decrease)*****(In
                millions, except per share amounts)*****Net
                Income (Loss)****By
                Business Segment:**Regulated
                Services
            
            
            
            
            $
            366
            
            $
            315
            
            $
            51
            
            $
            856
            
            $
            761
            
            $
            95Power
                supply
                management services
            
            
            
            
            
            10
            
            
            44
            
            
            (34
            )
            
            (15
            )
            
            79
            
            
            (94
            )Other
                and
                reconciling adjustments*
            
            
            
            
            
            (44
            )
            
            (60
            )
            
            16
            
            
            (171
            )
            
            (163
            )
            
            (8
            )Total
            
            
            
            
            $
            332
            
            $
            299
            
            $
            33
            
            $
            670
            
            $
            677
            
            $
            (7
            )**Basic
                Earnings Per Share:**Income
                before
                discontinued operations
            
            
            
            
            $
            1.01
            
            $
            0.90
            
            $
            0.11
            
            $
            1.99
            
            $
            2.05
            
            $
            (0.06
            )Discontinued
                operations
            
            
            
            
            
            --
            
            
            0.01
            
            
            (0.01
            )
            
            0.05
            
            
            0.02
            
            
            0.03Net
                earnings
                per basic share
            
            
            
            
            $
            1.01
            
            $
            0.91
            
            $
            0.10
            
            $
            2.04
            
            $
            2.07
            
            $
            (0.03
            )**Diluted
                Earnings Per Share:**Income
                before
                discontinued operations
            
            
            
            
            $
            1.01
            
            $
            0.90
            
            $
            0.11
            
            $
            1.98
            
            $
            2.04
            
            $
            (0.06
            )Discontinued
                operations
            
            
            
            
            
            --
            
            
            0.01
            
            
            (0.01
            )
            
            0.05
            
            
            0.02
            
            
            0.03Net
                earnings
                per diluted share
            
            
            
            
            $
            1.01
            
            $
            0.91
            
            $
            0.10
            
            $
            2.03
            
            $
            2.06
            
            $
            (0.03
            )*
                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
        regulated services segment for the three months and nine months ended
        September 30, 2005 increased due to additional customer demand. However,
        net income for the power supply management services segment was lower in
        both
        the three months and nine months ended September 30, 2005 compared to the
        same
        periods in 2004, as a result of higher costs for fossil fuel, purchased power
        (excluding 2004 PJM transactions on a gross basis) and nuclear refueling
        costs
        which, in aggregate, more than offset the revenue from increased electric
        generation sales.
 
 A
        decrease in
        wholesale electric revenues and purchased power costs in the 2005 periods
        compared to the corresponding periods last year primarily resulted from FES
        recording PJM sales and purchased power transactions on an hourly net position
        basis beginning in the first quarter of 2005 compared with recording each
        discrete transaction (on a gross basis) in 2004 (See Note 2 - Accounting
        for
        Wholesale Energy Transactions). This change had no impact on earnings and
        resulted from the dedication of FirstEnergy’s Beaver Valley Power Station to PJM
        in January 2005. Wholesale electric revenues and purchased power costs in
        the
        three months and nine months ended September 30, 2004 each included
        additional amounts of $264 million and $828 million, respectively, due to
        recording those transactions on a gross basis.
 
 Excluding
        the
        effect of recording the wholesale electric revenue transactions in PJM on
        a
        gross basis in 2004, total operating revenues in the three months and nine
        months ended September 30, 2005 increased 14.9% and 8.7%, respectively,
        reflecting in large part warmer than normal temperatures during the summer
        of
        2005 compared to 2004.


34




***Summary
        of Results of Operations - Third Quarter of 2005 compared with the Third
        Quarter
        of 2004***
 
 Financial
        results
        for FirstEnergy and its major business segments in the third quarter of 2005
        and
        2004 were as follows:


**Power****Supply**
            
            **Other
                and****3rd
                Quarter 2005**
            
            **Regulated**
            
            **Management**
            
            **Reconciling**
            
            **FirstEnergy****Quarterly
                Financial Results**
            
            **Services**
            
            **Services**
            
            **Adjustments**
            
            **Consolidated*****(In
                millions)***Revenue:ExternalElectric
            
            $
            1,432
            
            $
            1,684
            
            $
            --
            
            $
            3,116Other
            
            
            244
            
            
            28
            
            
            199
            
            
            471Internal
            
            
            79
            
            
            --
            
            
            (79
            )
            
            --Total
                Revenues
            
            
            1,755
            
            
            1,712
            
            
            120
            
            
            3,587Expenses:Fuel
                and
                purchased power
            
            
            --
            
            
            1,287
            
            
            --
            
            
            1,287Other
                operating
            
            
            511
            
            
            364
            
            
            118
            
            
            993Provision
                for
                depreciation
            
            
            137
            
            
            9
            
            
            7
            
            
            153Amortization
                of regulatory assets
            
            
            364
            
            
            --
            
            
            --
            
            
            364Deferral
                of
                new regulatory assets
            
            
            (124
            )
            
            --
            
            
            --
            
            
            (124
            )General
                taxes
            
            
            159
            
            
            24
            
            
            5
            
            
            188Total
                Expenses
            
            
            1,047
            
            
            1,684
            
            
            130
            
            
            2,861Net
                interest
                charges
            
            
            88
            
            
            11
            
            
            59
            
            
            158Income
                taxes
            
            
            254
            
            
            7
            
            
            (24
            )
            
            237Income
                before
                discontinued operations
            
            
            366
            
            
            10
            
            
            (45
            )
            
            331Discontinued
                operations
            
            
            --
            
            
            --
            
            
            1
            
            
            1Net
                Income
                (Loss)
            
            $
            366
            
            $
            10
            
            $
            (44
            )
            $
            332








**Power****Supply**
              
              **Other
                  and****3rd
                  Quarter 2004**
              
              **Regulated**
              
              **Management**
              
              **Reconciling**
              
              **FirstEnergy****Quarterly
                  Financial Results**
              
              **Services**
              
              **Services**
              
              **Adjustments**
              
              **Consolidated*****(In
                  millions)***Revenue:ExternalElectric
              
              $
              1,309
              
              $
              1,721
              
              $
              --
              
              $
              3,030Other
              
              
              172
              
              
              35
              
              
              148
              
              
              355Internal
              
              
              80
              
              
              --
              
              
              (80
              )
              
              --Total
                  Revenues
              
              
              1,561
              
              
              1,756
              
              
              68
              
              
              3,385Expenses:Fuel
                  and
                  purchased power
              
              
              --
              
              
              1,285
              
              
              --
              
              
              1,285Other
                  operating
              
              
              414
              
              
              356
              
              
              99
              
              
              869Provision
                  for
                  depreciation
              
              
              129
              
              
              9
              
              
              9
              
              
              147Amortization
                  of regulatory assets
              
              
              324
              
              
              --
              
              
              --
              
              
              324Deferral
                  of
                  new regulatory assets
              
              
              (79
              )
              
              --
              
              
              --
              
              
              (79
              )General
                  taxes
              
              
              150
              
              
              23
              
              
              5
              
              
              178Total
                  Expenses
              
              
              938
              
              
              1,673
              
              
              113
              
              
              2,724Net
                  interest
                  charges
              
              
              82
              
              
              9
              
              
              60
              
              
              151Income
                  taxes
              
              
              226
              
              
              30
              
              
              (42
              )
              
              214Income
                  before
                  discontinued operations
              
              
              315
              
              
              44
              
              
              (63
              )
              
              296Discontinued
                  operations
              
              
              --
              
              
              --
              
              
              3
              
              
              3Net
                  Income
                  (Loss)
              
              $
              315
              
              $
              44
              
              $
              (60
              )
              $
              299






35




**Change
                Between**
            
            
            
            **Power****3****rd****Quarter 2005 and 2004**
            
            
            
            **Supply**
            
            **Other
                and****Quarterly
                Financial Results**
            
            **Regulated**
            
            **Management**
            
            **Reconciling**
            
            **FirstEnergy****Increase
                (Decrease)**
            
            **Services**
            
            **Services**
            
            **Adjustments**(**1)**
            
            **Consolidated*****(In
                millions)***Revenue:ExternalElectric
            
            $
            123
            
            $
            (37
            )
            $
            --
            
            $
            86Other
            
            
            72
            
            
            (7
            )
            
            51
            
            
            116Internal
            
            
            (1
            )
            
            --
            
            
            1
            
            
            --Total
                Revenues
            
            
            194
            
            
            (44
            )
            
            52
            
            
            202Expenses:Fuel
                and
                purchased power
            
            
            --
            
            
            2
            
            
            --
            
            
            2Other
                operating
            
            
            97
            
            
            8
            
            
            19
            
            
            124Provision
                for
                depreciation
            
            
            8
            
            
            --
            
            
            (2
            )
            
            6Amortization
                of regulatory assets
            
            
            40
            
            
            --
            
            
            --
            
            
            40Deferral
                of
                new regulatory assets
            
            
            (45
            )
            
            --
            
            
            --
            
            
            (45
            )General
                taxes
            
            
            9
            
            
            1
            
            
            --
            
            
            10Total
                Expenses
            
            
            109
            
            
            11
            
            
            17
            
            
            137Net
                interest
                charges
            
            
            6
            
            
            2
            
            
            (1
            )
            
            7Income
                taxes
            
            
            28
            
            
            (23
            )
            
            18
            
            
            23Income
                before
                discontinued operations
            
            
            51
            
            
            (34
            )
            
            18
            
            
            35Discontinued
                operations
            
            
            --
            
            
            --
            
            
            (2
            )
            
            (2
            )Net
                Income
                (Loss)
            
            $
            51
            
            $
            (34
            )
            $
            16
            
            $
            33(1)The
                impact of
                the new Ohio tax legislation is included with FirstEnergy’s other
                operating segments and reconciling adjustments.





***Regulated
        Services - Third Quarter 2005 Compared with Third Quarter
        2004***
  Net
        income
        increased $51 million, or 16% to $366 million, in the third quarter of 2005
        compared to $315 million in the third quarter of 2004, as a result of increased
        customer usage.
 
 *Revenues
        -*
 
 Total
        revenues
        increased by $194 million in the third quarter 2005 compared to the same
        period
        in 2004, resulting from the following sources:







**Three
                Months Ended****September
                30,****Revenues
                by Type of Service**
            
            **2005**
            
            **2004**
            
            **Increase*****(In
                millions)***Distribution
                services
            
            $
            1,432
            
            $
            1,309
            
            $
            123Transmission
                services
            
            
            117
            
            
            81
            
            
            36Lease
                revenue
                from affiliates
            
            
            79
            
            
            79
            
            
            --Other
            
            
            127
            
            
            92
            
            
            35Total
                Revenues
            
            $
            1,755
            
            $
            1,561
            
            $
            194





Changes
        in
        distribution deliveries by customer class in the third quarter of 2005 compared
        with the third quarter of 2004 are summarized in the following
        table:


**Electric
                Distribution Deliveries**
            
            
            
            **Increase**Residential
            
            
            
            
            
            15.4
            %Commercial
            
            
            
            
            
            7.8
            %Industrial
            
            
            
            
            
            5.2
            %Total
                Distribution Deliveries
            
            
            
            
            
            9.6
            %






36




Increased
        consumption offset in part by lower composite prices to customers resulted
        in
        higher distribution delivery revenue. The following table summarizes major
        factors contributing to the $123 million increase in distribution services
        revenue in the third quarter of 2005:


**Increase****Sources
                of Change in Distribution Revenues**
            
            **(Decrease)*****(In
                millions)***Changes
                in
                customer usage
            
            $
            135Changes
                in
                prices:Rate
                changes
                --Ohio
                shopping
                credits
            
            
            (11
            )JCP&L
                rate settlements
            
            
            21Billing
                component reallocations
            
            
            (22
            )Net
                Increase
                in Distribution Revenues
            
            $
            123




Distribution
        revenues benefited from warmer summer temperatures in the third quarter of
        2005,
        compared to 2004, that increased the air-conditioning load of residential
        and
        commercial customers. While industrial deliveries also increased, that impact
        was more than offset by lower unit prices to that sector. Higher base rates
        from
        JCP&L's stipulated rate settlements were more than offset by additional
        credits provided to customers under the Ohio transition plan and a reallocation
        of billing components primarily related to special contracts. Shopping
        credits do not affect current period earnings due to deferral of the incentives
        for future recovery from customers.
  Transmission
        revenues increased $36 million in the third quarter of 2005 from the same
        period
        last year due in part to increased loads due to warmer weather and higher
        transmission usage prices. Other
        revenues
        increased $35 million primarily due to higher gains realized on nuclear
        decommissioning trust investments.
 
 *Expenses-*
 
 The
        increase in
        total revenues discussed above was partially offset by the following increases
        in total expenses:
 
 ·  Other
        operating
        expenses increased by $97 million in the third quarter of 2005 compared to
        the
        same
 period in 2004 primarily due to increased transmission expenses resulting
        in part from increased loads
 and
        higher transmission system usage charges;
 
 ·  Increased
        provision
        for depreciation of $8 million that resulted from property additions and
        increased
 leasehold improvement amortization;
 
 · Additional
        amortization of regulatory assets of $40 million, principally Ohio transition
        costs;
 
 ·
              Higher general taxes of $9 million resulting from increased EUOC
                  sales
                  which increased the Ohio KWH
                tax and the Pennsylvania gross receipts
                  tax;
 
 · Increased
        interest
        charges of $6 million primarily due to the absence of $11 million in interest
        rate swap
 savings achieved in the third quarter of 2004; and
 
 · Higher
        income taxes of $28 million due to increased taxable income.
  Partially
        offsetting those increases was the effect of additional deferred regulatory
        assets of $45 million, primarily due to the PUCO-approved deferral of MISO
        administrative costs, shopping incentives and related interest.
 
 ***Power
        Supply Management Services - Third Quarter 2005 Compared with Third Quarter
        2004***
 
 Net
        income for this
        segment decreased $34 million to $10 million in the third quarter of 2005
        from
        $44 million in the same period last year, due to a decrease in the gross
        generation margin and higher operating costs.


37


*Revenues
        -*
  Excluding
          the
          effect of the change in recording PJM wholesale transactions on a gross
          basis in
          2004 ($264 million), electric generation revenues increased $227
          million in
          the third quarter of 2005 compared to the same period of 2004 primarily
          as a
          result of a 5.2% increase in KWH sales due to higher retail customer usage
          and a
          21% rise in unit prices in the wholesale market. The increase in retail
          sales
          reduced energy available for sale to the wholesale market, resulting in
          a 9%
          reduction in wholesale sales (before the PJM adjustment).
 
 The
          change in
          reported segment revenues resulted from the following:


**Three
                Months Ended****September
                30,**
            
            **Increase****Revenues
                by Type of Service**
            
            **2005**
            
            **2004**
            
            **(Decrease)*****(In
                millions)***Electric
                generation sales:Retail
            
            $
            1,254
            
            $
            1,069
            
            $
            185Wholesale
            
            
            430
            
            
            388
            
            
            42Total
                electric generation sales
            
            
            1,684
            
            
            1,457
            
            
            227Transmission
            
            
            16
            
            
            20
            
            
            (4
            )Other
            
            
            12
            
            
            15
            
            
            (3
            )Total
            
            
            1,712
            
            
            1,492
            
            
            220PJM
                gross
                transactions
            
            
            --
            
            
            264
            
            
            (264
            )Total
                Revenues
            
            $
            1,712
            
            $
            1,756
            
            $
            (44
            )





The
        following table
        summarizes the price and volume factors contributing to increased sales to
        retail and wholesale customers.


**Increase****Source
                of Change in Electric Generation Sales**
            
            **(Decrease)*****(In
                millions)***Retail:Effect
                of
                9.9% increase in customer usage
            
            $
            113Change
                in
                prices
            
            
            72185Wholesale:Effect
                of
                8.7% reduction in customer usage(1)
            
            
            (41
            )Change
                in
                prices
            
            
            8342Net
                Increase
                in Electric Generation Sales
            
            $
            227(1)Decrease of
                46.4% including the effect of the PJM revision.








38




*Expenses
        -*
  Excluding
        the
        effect of $264 million of PJM purchased power costs recorded on a gross basis
        in
        2004, total operating expenses, net interest charges and income taxes increased
        in aggregate by $254 million in the third quarter of 2005 compared to the
        same
        period of 2004. Higher fuel and purchased power costs contributed $2 million
        ($266 million, net of $264 million PJM effect) of the increase, resulting
        from
        higher fuel costs of $121 million and increased purchased power costs of
        $145
        million. 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
            
            $
            92Change
                due to
                volume consumed
            
            
            29121Purchased
                Power:Change
                due to
                increased unit costs
            
            
            130Change
                due to
                volume purchased
            
            
            (16
            )Reduction
                in
                costs deferred
            
            
            31145PJM
                gross
                transactions
            
            
            (264
            )Net
                Increase
                in Fuel and Purchased Power Costs
            
            $
            2





FirstEnergy’s
        generation fleet established an output record of 21.7 billion KWH in the
        third
        quarter of 2005. As a result, increased coal consumption and the related
        cost of
        emission allowances combined to increase fossil fuel expense. Higher coal
        costs
        resulted from increased market purchases, market adjustment provisions in
        coal
        contracts reflecting higher market prices and increased transportation costs.
        Emission allowance costs increased primarily from higher prices. To a lesser
        extent, fuel expense increased due to higher costs associated with the increase
        in generation from the fossil units relative to nuclear generation. Fossil
        generation output increased 16% in the third quarter of 2005 while nuclear
        output increased by 1%, compared to the same period in 2004.
 
 Other
        operating
        costs increased $8 million in the third quarter of 2005 compared to the same
        period of 2004. This increase resulted from higher transmission costs due
        primarily to increased loads and higher transmission system usage charges.
        The
        higher costs this year were offset in part by lower non-fuel nuclear costs
        resulting from expenses incurred late in the third quarter of 2004 in
        preparation for the fourth quarter of 2004 Beaver Valley Unit 1 refueling
        outage.
 
 Offsetting
        higher
        operating costs were lower income taxes of $23 million due to lower taxable
        income.
 
 ***Other
        -
        Third Quarter 2005 Compared with Third Quarter 2004***
 
 FirstEnergy’s
        financial results from other operating segments and reconciling adjustments,
        including interest expense on holding company debt and corporate support
        services revenues and expenses, resulted in a net increase of $16 million
        in net
        income in the third quarter of 2005 compared to the same quarter of 2004.
        The
        increase was primarily due to the absence this year of losses recognized
        in 2004
        on the sale of securities and impairment of several partnership
        investments.


39




***Summary
        of Results of Operations - Nine Months ended September 30, 2005 compared
        with
        the Nine Months ended September 30, 2004***
 
 Financial
        results
        for FirstEnergy and its major business segments for the nine months ended
        September 30, 2005 and 2004 were as follows:




**Power****Supply**
            
            **Other
                and****Nine
                Months ended September 30, 2005**
            
            
            **Regulated**
            
            **Management**
            
            **Reconciling**
            
            **FirstEnergy****Financial
                Results**
            
            
            **Services**
            
            **Services**
            
            **Adjustments**
            
            **Consolidated*****(In
                millions)***Revenue:ExternalElectric
            
            
            
            $
            3,759
            
            $
            4,273
            
            $
            -
            
            $
            8,032Other
            
            
            
            
            607
            
            
            73
            
            
            565
            
            
            1,245Internal
            
            
            
            
            237
            
            
            -
            
            
            (237
            )
            
            -Total
                Revenues
            
            
            
            
            4,603
            
            
            4,346
            
            
            328
            
            
            9,277Expenses:Fuel
                and
                purchased power
            
            
            
            
            -
            
            
            3,115
            
            
            -
            
            
            3,115Other
                operating
            
            
            
            
            1,336
            
            
            1,132
            
            
            290
            
            
            2,758Provision
                for
                depreciation
            
            
            
            
            397
            
            
            26
            
            
            21
            
            
            444Amortization
                of regulatory assets
            
            
            
            
            982
            
            
            -
            
            
            -
            
            
            982Deferral
                of
                new regulatory assets
            
            
            
            
            (303
            )
            
            -
            
            
            -
            
            
            (303
            )General
                taxes
            
            
            
            
            455
            
            
            69
            
            
            17
            
            
            541Total
                Expenses
            
            
            
            
            2,867
            
            
            4,342
            
            
            328
            
            
            7,537Net
                interest
                charges
            
            
            
            
            285
            
            
            29
            
            
            175
            
            
            489Income
                taxes
            
            
            
            
            595
            
            
            (10
            )
            
            14
            
            
            599Income
                before
                discontinued operations
            
            
            
            
            856
            
            
            (15
            )
            
            (189
            )
            
            652Discontinued
                operations
            
            
            
            
            -
            
            
            -
            
            
            18
            
            
            18Net
                Income
                (Loss)
            
            
            
            $
            856
            
            $
            (15
            )
            $
            (171
            )
            $
            670








**Power****Supply**
            
            **Other
                and****Nine
                Months ended September 30, 2004**
            
            
            **Regulated**
            
            **Management**
            
            **Reconciling**
            
            **FirstEnergy****Financial
                Results**
            
            
            **Services**
            
            **Services**
            
            **Adjustments**
            
            **Consolidated*****(In
                millions)***Revenue:ExternalElectric
            
            
            
            $
            3,588
            
            $
            4,742
            
            $
            --
            
            $
            8,330Other
            
            
            
            
            461
            
            
            86
            
            
            484
            
            
            1,031Internal
            
            
            
            
            239
            
            
            --
            
            
            (239
            )
            
            --Total
                Revenues
            
            
            
            
            4,288
            
            
            4,828
            
            
            245
            
            
            9,361Expenses:Fuel
                and
                purchased power
            
            
            
            
            --
            
            
            3,515
            
            
            --
            
            
            3,515Other
                operating
            
            
            
            
            1,155
            
            
            1,058
            
            
            288
            
            
            2,501Provision
                for
                depreciation
            
            
            
            
            384
            
            
            26
            
            
            29
            
            
            439Amortization
                of regulatory assets
            
            
            
            
            905
            
            
            --
            
            
            --
            
            
            905Deferral
                of
                new regulatory assets
            
            
            
            
            (192
            )
            
            --
            
            
            --
            
            
            (192
            )General
                taxes
            
            
            
            
            433
            
            
            65
            
            
            16
            
            
            514Total
                Expenses
            
            
            
            
            2,685
            
            
            4,664
            
            
            333
            
            
            7,682Net
                interest
                charges
            
            
            
            
            301
            
            
            30
            
            
            171
            
            
            502Income
                taxes
            
            
            
            
            541
            
            
            55
            
            
            (90
            )
            
            506Income
                before
                discontinued operations
            
            
            
            
            761
            
            
            79
            
            
            (169
            )
            
            671Discontinued
                operations
            
            
            
            
            --
            
            
            --
            
            
            6
            
            
            6Net
                Income
                (Loss)
            
            
            
            $
            761
            
            $
            79
            
            $
            (163
            )
            $
            677








40








**Power****Change
                Between Nine Months ended**
            
            
            
            
            **Supply**
            
            **Other
                and****September
                30, 2005 vs. 2004**
            
            
            **Regulated**
            
            **Management**
            
            **Reconciling**
            
            **FirstEnergy****Financial
                Results**
            
            
            **Services**
            
            **Services**
            
            **Adjustments****(1)**
            
            **Consolidated****Increase
                (Decrease)**
            
            
            ***(In
                millions)***Revenue:ExternalElectric
            
            
            
            $
            171
            
            $
            (469
            )
            $
            -
            
            $
            (298
            )Other
            
            
            
            
            146
            
            
            (13
            )
            
            81
            
            
            214Internal
            
            
            
            
            (2
            )
            
            -
            
            
            2
            
            
            -Total
                Revenues
            
            
            
            
            315
            
            
            (482
            )
            
            83
            
            
            (84
            )Expenses:Fuel
                and
                purchased power
            
            
            
            
            -
            
            
            (400
            )
            
            -
            
            
            (400
            )Other
                operating
            
            
            
            
            181
            
            
            74
            
            
            2
            
            
            257Provision
                for
                depreciation
            
            
            
            
            13
            
            
            -
            
            
            (8
            )
            
            5Amortization
                of regulatory assets
            
            
            
            
            77
            
            
            -
            
            
            -
            
            
            77Deferral
                of
                new regulatory assets
            
            
            
            
            (111
            )
            
            -
            
            
            -
            
            
            (111
            )General
                taxes
            
            
            
            
            22
            
            
            4
            
            
            1
            
            
            27Total
                Expenses
            
            
            
            
            182
            
            
            (322
            )
            
            (5
            )
            
            (145
            )Net
                interest
                charges
            
            
            
            
            (16
            )
            
            (1
            )
            
            4
            
            
            (13
            )Income
                taxes
            
            
            
            
            54
            
            
            (65
            )
            
            104
            
            
            93Income
                before
                discontinued operations
            
            
            
            
            95
            
            
            (94
            )
            
            (20
            )
            
            (19
            )Discontinued
                operations
            
            
            
            
            -
            
            
            -
            
            
            12
            
            
            12Net
                Income
                (Loss)
            
            
            
            $
            95
            
            $
            (94
            )
            $
            (8
            )
            $
            (7
            )(1)The impact
                of the new Ohio tax legislation is included with FirstEnergy's other
                operating segments and reconciling
                adjustments.





***Regulated
        Services - Nine Months ended September 30, 2005 compared with Nine Months
        ended
        September 30, 2004***
  Net
        income
        increased $95 million to $856 million in the nine months ended September
        30,
        2005, from $761 million in the same period of 2004, due to increased revenues
        partially offset by higher expenses and taxes.
 
 *Revenues
        -*
 
 The
        increase in
        total revenues resulted from the following:


**Nine
                Months Ended****September
                30,**
            
            **Increase****Revenues
                by Type of Service**
            
            **2005**
            
            **2004**
            
            **(Decrease)*****(In
                millions)***Distribution
                services
            
            $
            3,759
            
            $
            3,588
            
            $
            171Transmission
                services
            
            
            314
            
            
            210
            
            
            104Lease
                revenue
                from affiliates
            
            
            237
            
            
            239
            
            
            (2
            )Other
            
            
            293
            
            
            251
            
            
            42Total
                Revenues
            
            $
            4,603
            
            $
            4,288
            
            $
            315





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


**Electric
                Distribution Deliveries**
            
            **Increase**Residential
            
            
            7.9
            %Commercial
            
            
            5.2
            %Industrial
            
            
            1.8
            %Total
                Distribution Deliveries
            
            
            5.0
            %









41


Increased
          customer
          consumption offset in part by lower prices resulted in higher distribution
          delivery revenues. The following table summarizes major factors contributing
          to
          the $171 million increase in distribution services revenue in the first
          nine
          months of 2005:
 **Increase****Sources
                  of Change in Distribution Revenues**
              
              **(Decrease)*****(In
                  millions)***Changes
                  in
                  customer usage
              
              $
              210Changes
                  in
                  prices:Rate
                  changes
                  -Ohio
                  shopping
                  credits
              
              
              (33
              )JCP&L
                  rate settlements
              
              
              28Billing
                  component reallocation
              
              
              (34
              )Net
                Increase
                in Distribution Revenues
              
              $
              171
  Distribution
          revenues benefited from warmer temperatures in the summer months of 2005
          compared to 2004 that increased the air-conditioning load of residential
          and
          commercial customers. The effect of higher base rates for JCP&L's stipulated
          rate settlements in 2005 were more than offset by additional credits provided
          to
          customers under the Ohio transition plan and a reallocation of billing
          components primarily related to special contracts. Shopping credits do
          not
          affect current period earnings due to deferral of the incentives for future
          recovery from customers. While
          industrial
          deliveries also increased they were more than offset by lower unit
          prices.
 
 Transmission
          revenues increased $104 million in the nine months ended September 30,
          2005
          compared to the same period last year due in part to the June 2004 amended
          power
          supply agreement with FES and increased loads due to warmer summer weather
          and
          higher transmission usage prices. Other revenues increased $42 million primarily
          due to
          higher gains realized on nuclear decommissioning trust investments.
 
 *Expenses-*
  Total
          operating
          expenses, net of interest charges and income taxes increased in aggregate
          by
          $220 million in the nine months ended September 30, 2005 compared to the
          same
          period in 2004 due to the following:
 
 ·
                  Other
                      operating expenses increased $181 million principally due to
                      higher
                      transmission expenses resulting from an amended power supply
                      agreement
                      with FES, increased loads, and higher transmission system usage
                      charges;
 ·
                  Provision
                      for
                      depreciation increased $13 million reflecting the effect of
                      property
                      additions, additional costs for decommissioning the Saxton
                      nuclear unit
                      and increased leasehold improvement amortization, reflecting
                      shorter lives
                      associated with capital additions for leased generating plants
                      of the Ohio
                      Companies to correspond to the remaining lease
                      terms;
 ·
                Additional
                    amortization of regulatory assets of $77 million, principally
                    Ohio
                    transition costs;
   ·
                Higher general taxes of $22 million resulting from increased
                    EUOC sales
                    which increased the Ohio KWH
                  tax and the Pennsylvania gross receipts tax and the absence in
                    2005 of
                    Pennsylvania property tax
                  refunds
                    recognized in 2004; and
 
 ·
                Higher
                    income
                    taxes of $54 million due to increased taxable
                    income.
 
 The
          following
          partially offset these higher costs:
 
 ·
                Additional
                    deferrals of regulatory assets of $111 million, stemming from
                    the deferral
                    of PUCO-approved
                  MISO
                    administrative costs, JCP&L reliability improvements, shopping
                    incentive credits and relat
                  interest
                    on
                    those deferrals (see Note 14 - Regulatory Matters - Transmission,
                    New
                    Jersey); and
 
 ·
                Lower
                    interest charges of $16 million resulting from debt and preferred
                    stock
                    redemptions and refinancings.
 42
  ***Power
                    Supply Management Services - Nine Months ended September 30,
                    2005 compared
                    with the Nine Months ended September 30,
                    2004***
  The
          net loss for
          this segment was $15 million for the nine months ended September 30,
          2005
          compared to net income of $79 million in the same period last year.
          A
          reduction in the gross generation margin, higher nuclear operating costs
          and
          amounts recognized for fines, penalties and obligations associated with
          proceedings involving the W.H. Sammis Plant and the Davis-Besse Nuclear
          Power
          Station contributed to the 2005 net loss.
 
 *Revenues
          -*
  Excluding
          the
          effect of the change in recording PJM wholesale transactions on a gross
          basis in
          2004 ($828 million), electric generation revenues increased $359
          million in
          the nine months ended September 30, 2005 compared to the same period
          of
          2004 as a result of a 2.4% increase in KWH sales and higher unit prices.
 
 The
          change in
          reported segment revenues resulted from the following:
 **Nine
                  Months Ended****September
                  30,**
              
              **Increase****Revenues
                  by Type of Service**
              
              **2005**
              
              **2004**
              
              **(Decrease)*****(In
                  millions)***Electric
                  generation sales:Retail
              
              $
              3,223
              
              $
              2,933
              
              $
              290Wholesale(1)
              
              
              1,050
              
              
              981
              
              
              69Total
                  Electric Generation Sales
              
              
              4,273
              
              
              3,914
              
              
              359Transmission
              
              
              41
              
              
              57
              
              
              (16
              )Other
              
              
              32
              
              
              29
              
              
              3Total
              
              
              4,346
              
              
              4,000
              
              
              346PJM
                  gross
                  transactions
              
              
              -
              
              
              828
              
              
              (828
              )Total
                  Revenues
              
              $
              4,346
              
              $
              4,828
              
              $
              (482
              )(1)Excluding
                  2004 PJM effect of gross transactions.
 
 Higher
          electric
          generation sales resulted from increased unit prices and increased retail
          customer usage. The following table summarizes the price and volume factors
          contributing to the increased sales to retail and wholesale
          customers.
  **Source
                  of Change in Electric Generation Sales*****(In
                  millions)***Retail:Effect
                  of
                  4.5% increase in customer usage
              
              $
              140Change
                  in
                  prices
              
              
              150290Wholesale:Effect
                  of
                  4.4% reduction in customer usage(1)
              
              
              (48
              )Change
                  in
                  prices
              
              
              11769Net
                  Increase
                  in Electric Generation Sales
              
              $
              359(1)Decrease of
                  47.3% including the effect of the PJM revision.
 
 
  43
 *Expenses
          -*
  Excluding
          the
          effect of $828 million of PJM purchased power costs recorded on a gross
          basis in
          2004, total operating expenses, net interest charges and income taxes increased
          in aggregate by $440 million in the nine months ended September 30,
          2005
          compared to the same period of 2004. Higher
          fuel and
          purchased power costs contributed $428 million of the increase,
          resulting
          from higher fuel costs of $245 million and increased purchased power costs
          of
          $183 million. 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
                  unit costs
              
              $
              212Change
                  due to
                  volume consumed
              
              
              33245Purchased
                  Power:Change
                  due to
                  unit costs
              
              
              255Change
                  due to
                  volume purchased
              
              
              (53
              )Increase in
                  deferred costs
              
              
              (19
              )183PJM
                  Gross
                  Transactions
              
              
              (828
              )Net
                  Decrease
                  in Fuel and Purchased Power Costs
              
              $
              (400
              )
 
 FirstEnergy’s
            generation fleet established an output record of 59.5 billion KWH for
            the nine
            months ended September 30, 2005. Higher coal costs resulted from
            increased
            consumption, market adjustment provisions in coal contracts reflecting
            higher
            market prices and increased transportation costs. Emission allowance
            costs
            increased primarily from higher prices. To a lesser extent, fuel expense
            increased due to the mix of fossil versus nuclear generation resulting
            from the
            nuclear refueling outages in the first nine months of 2005 following
            a year with
            no scheduled nuclear refueling outages and improved performance of fossil
            generating units. Fossil generation increased 12% in the nine months
            ended
            September 30, 2005 while nuclear generation decreased by 8% compared
            to the
            same period of 2004.
 
 Other
            operating
            costs increased $74 million in the nine months ended September 30, 2005
            compared
            to the same period of 2004. This increase resulted from higher non-fuel
            nuclear
            costs. The increase in non-fuel nuclear costs resulted from 2005 refueling
            outages at Perry Unit 1 (including an unplanned extension) and Beaver
            Valley
            Unit 2 and a scheduled 23-day mid-cycle inspection outage at the Davis-Besse
            nuclear plant. There were no scheduled nuclear refueling outages in the
            first
            nine months of 2004. Also included in other operating costs for 2005
            were the
            EPA settlement loss and NRC fine described above. Offsetting the higher
            other
            operating costs were reduced non-fuel fossil generation expense of $17
            million
            due to reduced maintenance outages in 2005 and lower transmission costs
            of $15
            million, due to an amended power supply agreement with Met-Ed and Penelec.
 
 Partially
            offsetting the increase in other operating costs were lower income taxes
            of $65
            million due to lower taxable income.
 
 ***Other
            -
            Nine Months ended September 30, 2005 compared with the Nine Months ended
            September 30, 2004***
 
 FirstEnergy’s
            financial results from other operating segments and reconciling adjustments,
            including interest expense on holding company debt and corporate support
            services revenues and expenses and the impacts of the new Ohio tax legislation
            (discussed below) resulted in a decrease in FirstEnergy’s net income in the nine
            months ended September 30, 2005 compared to the same period of 2004.
            The
            decrease primarily reflected the effect of the new Ohio tax legislation
            partially offset by the effect of discontinued operations, which included
            an
            after-tax net gain of $17 million in 2005 (see Note 6). The following
            table
            summarizes the sources of income from discontinued
            operations:
 **Nine
                  Months Ended****September
                  30,**
              
              **Increase****2005**
              
              **2004**
              
              **(Decrease)*****(In
                  millions)***Discontinued
                  operations (net of tax)Gain
                  on
                  sale:Retail
                  gas
                  business
              
              $
              5
              
              $
              -
              
              $
              5FSG
                  and MYR
                  Subsidiaries
              
              
              12
              
              
              -
              
              
              12Reclassification
                  of operating income
              
              
              2
              
              
              6
              
              
              (4
              )Total
              
              $
              19
              
              $
              6
              
              $
              13
 
   44
 On
          June 30,
          2005, the State of Ohio enacted new tax legislation that created a new
          CAT tax,
          which is based on qualifying “taxable gross receipts” and will not consider any
          expenses or costs incurred to generate such receipts, except for items
          such as
          cash discounts, returns and allowances, and bad debts. The CAT tax was
          effective
          July 1, 2005, and replaces the Ohio income-based franchise tax and
          the Ohio
          personal property tax. The CAT tax is phased-in while the current income-based
          franchise tax is phased-out over a five-year period at a rate of 20% annually,
          beginning with the year ended 2005, and the personal property tax is phased-out
          over a four-year period at a rate of approximately 25% annually, beginning
          with
          the year ended 2005. For example, during the phase-out period the Ohio
          income-based franchise tax will be computed consistently with the prior
          tax law,
          except that the tax liability as computed will be multiplied by 4/5 in
          2005; 3/5
          in 2006; 2/5 in 2007 and 1/5 in 2008, therefore eliminating the current
          income-based franchise tax over a five-year period. As a result of the
          new tax
          structure, all net deferred tax benefits that are not expected to reverse
          during
          the five-year phase-in period were written-off as of June 30, 2005. The
          impact on income taxes associated with the required adjustment to net deferred
          taxes for the nine months ended September 30, 2005 was an additional
          tax
          expense of approximately $72 million, which was partially offset by the
          initial
          phase-out of the Ohio income-based franchise tax, which reduced income
          taxes by
          approximately $8 million in the nine months ended September 30,
          2005. See
          Note 12 to the consolidated financial statements.
 
 ***Postretirement
          Benefits***
 
 Postretirement
          benefits expense decreased by $17 million in the third quarter of 2005
          and $54
          million in the nine months ended September 30, 2005 compared to the
          corresponding periods of 2004. Pension costs represent most of the reduction
          due
          to a $500 million voluntary contribution made in 2004 and an increase in
          the
          market value of plan assets during 2004. The following table summarizes
          the net
          pension and OPEB expense (excluding amounts capitalized) for the three
          months
          and nine months ended September 30, 2005 and 2004.
 **Three
                  Months Ended**
              
              
              
              **Nine
                  Months Ended****Postretirement**
              
              **September
                  30,**
              
              **Increase**
              
              **September
                  30,**
              
              **Increase****Benefits
                  Expense ***
              
              **2005**
              
              **2004**
              
              **(Decrease)**
              
              **2005**
              
              **2004**
              
              **(Decrease)*****(In
                  millions)***Pension
              
              $
              8
              
              $
              21
              
              $
              (13
              )
              $
              24
              
              $
              64
              
              $
              (40
              )OPEB
              
              
              18
              
              
              22
              
              
              (4
              )
              
              54
              
              
              68
              
              
              (14
              )Total
              
              $
              26
              
              $
              43
              
              $
              (17
              )
              $
              78
              
              $
              132
              
              $
              (54
              )*
                  Excludes
                  the capitalized portion of postretirement benefits costs (see Note
                  10 for
                  total costs).
 
 The
          decrease in
          pension and OPEB expenses are included in various cost categories and have
          contributed to other cost reductions discussed above.
 
 **CAPITAL
          RESOURCES AND LIQUIDITY**
 
 FirstEnergy’s
          cash
          requirements in 2005 for operating expenses, construction expenditures,
          scheduled debt maturities and preferred stock redemptions are expected
          to be met
          without increasing FirstEnergy’s net debt and preferred stock outstanding.
          Borrowing capacity under credit facilities is available to manage working
          capital requirements.
 
 ***Changes
          in Cash Position***
 
 The
          primary source
          of ongoing cash for FirstEnergy, as a holding company, is cash dividends
          from
          its subsidiaries. The holding company also has access to $2.0 billion of
          short-term financing under a revolving credit facility, subject to short-term
          debt limitations under current regulatory approvals of $1.5 billion and
          to
          outstanding borrowings by subsidiaries of FirstEnergy who are also parties
          to
          such facility. In the third quarter of 2005, FirstEnergy received
          $306 million of cash dividends from its subsidiaries and paid $141
          million
          in cash dividends to its common shareholders - in the first nine months
          of 2005,
          it received and paid $846 million and $412 million, respectively. There
          are no
          material restrictions on the payment of cash dividends by FirstEnergy’s
          subsidiaries.
 
 As
          of
          September 30, 2005, FirstEnergy had $140 million of cash and cash
          equivalents ($3 million restricted as an indemnity reserve) compared with
          $53
          million ($3 million restricted as an indemnity reserve) as of December 31,
          2004. The major sources for changes in these balances are summarized
          below.
 45
 
 ***Cash
        Flows From Operating Activities***
 
 FirstEnergy's
          consolidated net cash from operating activities is provided primarily by
          its
          regulated and power supply businesses (see “RESULTS OF OPERATIONS” above). Net
          cash provided by operating activities was $981 million and $528 million
          in the
          third quarter of 2005 and 2004, respectively, and $1.9 billion and $1.5
          billion
          in the first nine months of 2005 and 2004, respectively, summarized as
          follows:
 **Three
                  Months Ended**
              
              **Nine
                  Months Ended****September
                  30,**
              
              **September
                  30,****Operating
                  Cash Flows**
              
              **2005**
              
              **2004**
              
              **2005**
              
              **2004*****(In
                  millions)***Cash
                  earnings(1)
              
              $
              777
              
              $
              545
              
              $
              1,642
              
              $
              1,427Pension
                  trust
                  contribution(2)
              
              
              -
              
              
              (300
              )
              
              -
              
              
              (300
              )Working
                  capital and other
              
              
              204
              
              
              283
              
              
              270
              
              
              411Total
                  cash
                  flows from operating activities
              
              $
              981
              
              $
              528
              
              $
              1,912
              
              $
              1,538(1)Cash
                  earnings are a non-GAAP measure (see reconciliation
                  below).(2)Pension
                  trust contribution net of $200 million of income tax
                  benefits.
  Cash
          earnings, as
          disclosed 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. The
          following table reconciles cash earnings with net income.
 **Three
                  Months Ended**
              
              **Nine
                  Months Ended****September
                  30,**
              
              **September
                  30,****Reconciliation
                  of Cash Earnings**
              
              **2005**
              
              **2004**
              
              **2005**
              
              **2004*****(In
                  millions)***Net
                  income
                  (GAAP)
              
              $
              332
              
              $
              299
              
              $
              670
              
              $
              677Non-cash
                  charges (credits):Provision
                  for
                  depreciation
              
              
              153
              
              
              147
              
              
              444
              
              
              439Amortization
                  of regulatory assets
              
              
              364
              
              
              324
              
              
              982
              
              
              905Deferral
                  of
                  new regulatory assets
              
              
              (124
              )
              
              (79
              )
              
              (303
              )
              
              (191
              )Nuclear
                  fuel
                  and lease amortization
              
              
              26
              
              
              27
              
              
              63
              
              
              72Deferred
                  purchased power and other costs
              
              
              (39
              )
              
              (118
              )
              
              (231
              )
              
              (263
              )Deferred
                  income taxes and investment tax credits(1)
              
              
              (38
              )
              
              (163
              )
              
              24
              
              
              (257
              )Deferred
                  rents and lease market valuation liability
              
              
              30
              
              
              28
              
              
              (71
              )
              
              (52
              )Accrued
                  retirement benefit obligations
              
              
              56
              
              
              42
              
              
              104
              
              
              107Income
                  from
                  discontinued operations
              
              
              (1
              )
              
              (2
              )
              
              (18
              )
              
              (6
              )Other
                  non-cash expenses
              
              
              18
              
              
              40
              
              
              (22
              )
              
              (4
              )Cash
                  earnings
                  (non-GAAP)
              
              $
              777
              
              $
              545
              
              $
              1,642
              
              $
              1,427(1)Excludes
                  $200 million of deferred tax benefits from pension contribution
                  in
                  2004.
 
 In
          the three months
          and nine months ended September 30, 2005, cash earnings increased $232
          million
          and $215 million, respectively. Both periods benefited from increased generation
          and distribution revenues aided by warmer summer temperatures that increased
          air
          conditioning load. In the third quarter of 2005 compared with the third
          quarter
          of 2004, cash provided from working capital decreased by $79 million, primarily
          due to changes in receivables. The use of cash for receivables resulted
          in part
          from the conversion of the CFC accounts receivable financing to an on-balance
          sheet transaction, which added $35 million of receivables to the balance
          sheet
          as of September 30, 2005. In the first nine months of 2005 compared
          to the
          first nine months of 2004, working capital changes provided $141 million
          less
          cash due in part to changes in receivables, materials and supplies, prepayments
          and accrued taxes, offset by accounts payable and the funds received as
          prepayment for electric usage, under the three-year Energy for Education
          II
          Program with the Ohio Schools Council.
  46
 **Cash
          Flows
          From Financing Activities**
  In
          the third
          quarter and first nine months of 2005, cash used for financing activities
          was
          $580 million and $1.0 billion, respectively, compared to $602 million
          and
          $1.4 billion in the third quarter and first nine months of 2004, respectively.
          The following table summarizes security issuances and
          redemptions.
 
 **Three
                  Months Ended**
              
              **Nine
                  Months Ended****September
                  30,**
              
              **September
                  30,****Securities
                  Issued or Redeemed**
              
              **2005**
              
              **2004**
              
              **2005**
              
              **2004*****(In
                  millions)****New
                  issues*Pollution
                  control notes
              
              $
              89
              
              $
              77
              
              $
              334
              
              $
              261Secured
                  notes
              
              
              -
              
              
              -
              
              
              -
              
              
              550Long-term
                  revolving credit
              
              
              -
              
              
              10
              
              
              -
              
              
              -Unsecured
                  notes
              
              
              -
              
              
              -
              
              
              -
              
              
              150$
              89
              
              $
              87
              
              $
              334
              
              $
              961*Redemptions*First
                  mortgage bonds
              
              $
              -
              
              $
              206
              
              $
              178
              
              $
              588Pollution
                  control notes
              
              
              130
              
              
              80
              
              
              377
              
              
              80Secured
                  notes
              
              
              25
              
              
              374
              
              
              74
              
              
              447Long-term
                  revolving credit
              
              
              -
              
              
              -
              
              
              215
              
              
              300Unsecured
                  notes
              
              
              8
              
              
              112
              
              
              8
              
              
              337Preferred
                  stock
              
              
              30
              
              
              1
              
              
              170
              
              
              1$
              193
              
              $
              773
              
              $
              1,022
              
              $
              1,753Short-term
                  borrowings, net increase (decrease)
              
              $
              (308
              )
              $
              228
              
              $
              77
              
              $
              (219
              )
 
 FirstEnergy
          had
          approximately $247 million of short-term indebtedness as of September 30,
          2005 compared to approximately $170 million as of December 31, 2004.
          Available bank borrowings as of September 30, 2005 included the
          following:
 **Borrowing
                  Capability**
              
              **FirstEnergy**
              
              
              **Penelec**
              
              **Total*****(In
                  millions)***Short-term
                  credit(1)
              
              $
              2,020
              
              
              $
              -
              
              $
              2,020Utilized
              
              
              -
              
              
              
              -
              
              
              -Letters
                  of
                  credit
              
              
              (137
              )
              
              
              -
              
              
              (137
              )Net
              
              
              1,883
              
              
              
              -
              
              
              1,883Short-term
                  bank facilities(2)
              
              
              -
              
              
              
              75
              
              
              75Utilized
              
              
              -
              
              
              
              (75
              )
              
              (75
              )Net
              
              
              -
              
              
              
              -
              
              
              -Total
                  unused
                  borrowing capability
              
              $
              1,883
              
              
              $
              -
              
              $
              1,883(1)A $2 billion
                    revolving credit facility is available in various amounts to
                    FirstEnergy
                    and certain
                  of
                    its
                    subsidiaries, including  Penelec. A $20 million uncommitted
                    line of
                    credit facility added
                  in
                    September
                    2005 is available to FirstEnergy only.(2)Penelec bank
                  facility terminated on October 7,
                  2005.
 
 As
          of October 24,
          2005, the Ohio Companies and Penn had the aggregate capability to issue
          approximately $3.8 billion of additional FMB on the basis of property additions
          and retired bonds under the terms of their respective mortgage indentures
          following the recently completed intra-system transfer of fossil and
          hydroelectric generating plants (See Note 17). 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 $690 million and $582 million, respectively, as of October 24, 2005.
          Under
          the provisions of its senior note indenture, JCP&L may issue additional FMB
          only as collateral for senior notes. As of October 24, 2005, JCP&L had the
          capability to issue $673 million of additional senior notes upon the basis
          of
          FMB collateral. Based upon applicable earnings coverage tests in their
          respective charters, OE, Penn, TE and JCP&L could issue a total of $4.9
          billion of preferred stock (assuming no additional debt was issued) as
          of
          September 30, 2005. It is estimated that the annualized impact of
          the
          intra-system transfer of fossil and hydroelectric generating plants will
          reduce
          the aggregate capability of OE, Penn, TE and JCP&L to issue preferred stock
          by approximately 10%. CEI, Met-Ed and Penelec have no restrictions on the
          issuance of preferred stock.
  47
  As
          of
          September 30, 2005, approximately $1 billion remained unused under
          an
          existing shelf registration statement, filed by FirstEnergy with the SEC
          in
          2003, to support future securities issues. 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.
 
 FirstEnergy’s
          and
          its subsidiaries' working capital and short-term borrowing needs are met
          principally with a $2 billion five-year revolving credit facility
          (included
          in the table above). Borrowings under the facility are available to each
          borrower separately and will mature on the earlier of 364 days from the
          date of
          borrowing and the commitment termination date.
 
 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**
              
              $
              2,000
              
              $
              1,500**OE**
              
              
              500
              
              
              500**Penn**
              
              
              50
              
              
              51**CEI**
              
              
              250
              
              
              500**TE**
              
              
              250
              
              
              500**JCP&L**
              
              
              425
              
              
              416**Met-Ed**
              
              
              250
              
              
              300**Penelec**
              
              
              250
              
              
              300**FES**
              
              
              -2
              
              
              n/a**ATSI**
              
              
              -2
              
              
              26
 
 (1) As
          of
          September 30, 2005.
 (2)
                Borrowing
                    sublimits 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 ($395 million
          unused as
          of September 30, 2005) of accounts receivable financing facilities
          for OE,
          CEI, TE, Met-Ed, Penelec and Penn, are intended to provide liquidity to
          meet
          short-term working capital requirements for FirstEnergy and its
          subsidiaries.
 
 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.
          Total unused borrowing capability under existing credit facilities and
          accounts
          receivable financing facilities totaled $2.36 billion as of September 30,
          2005.
 
 The
          revolving
          credit facility contains financial covenants requiring each borrower to
          maintain
          a consolidated debt to total capitalization ratio of no more than 0.65
          to 1.00.
          On October 3, 2005, FirstEnergy obtained a senior unsecured debt rating
          upgrade
          to BBB- by S&P removing the requirement under the revolving credit facility
          to maintain a fixed charge ratio of at least 2.00 to 1.00.
 
 As
          of
          September 30, 2005, FirstEnergy and subsidiaries’ debt to total
          capitalization as defined under the revolving credit facility, were as
          follows:
 **Debt****To
                      Total****Borrower**
                  
                  **Capitalization****FirstEnergy**
                  
                  
                  0.54
                      to
                      1.00**OE**
                  
                  
                  0.39
                      to
                      1.00**Penn**
                  
                  
                  0.32
                      to
                      1.00**CEI**
                  
                  
                  0.57
                      to
                      1.00**TE**
                  
                  
                  0.43
                      to
                      1.00**JCP&L**
                  
                  
                  0.29
                      to
                      1.00**Met-Ed**
                  
                  
                  0.38
                      to
                      1.00**Penelec**
                  
                  
                  0.34
                      to
                      1.00
    48
 The
          facility does
          not contain any 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 third quarter of 2005 was 3.50% for the regulated
          companies’ money pool and 3.46% for the unregulated companies' money
          pool.
 
 On
          July 18,
          2005, Moody’s revised its rating outlook on FirstEnergy and its subsidiaries to
          positive from stable. Moody’s stated that the revision to FirstEnergy’s outlook
          resulted from steady financial improvement and steps taken by management
          to
          improve operations, including the stabilization of its nuclear operations.
          Moody’s further stated that the revision in their outlook recognized
          management’s regional strategy of focusing on its core utility businesses and
          the improvement in FirstEnergy’s credit profile stemming from the application of
          free cash flow toward debt reduction. Moody’s noted that a ratings upgrade could
          be considered if FirstEnergy continues to achieve planned improvements
          in its
          operations and balance sheet.
 
 On
          October 3,
          2005, S&P raised its corporate credit rating on FirstEnergy and the EUOC to
          'BBB' from 'BBB-'. At the same time, S&P raised the senior unsecured ratings
          at the holding company to 'BBB-' from 'BB+' and each of the EUOC by one
          notch
          above the previous rating. S&P noted that the upgrade followed the
          continuation of a good operating track record, specifically for the nuclear
          fleet through the third quarter 2005. S&P also stated that FirstEnergy’s
          rating reflects the benefits of supportive regulation, low-cost base load
          generation fleet, low-risk transmission and distribution operations and
          rate
          certainty in Ohio. FirstEnergy’s ability to consistently generate free cash
          flow, good liquidity, and an improving financial profile were also noted
          as
          strengths.
 
 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 its EUOC’s
          securities ratings as of October 3, 2005. The ratings outlook from
          S&P
          and Fitch on all securities is stable. Moody’s outlook on all securities is
          Positive.
 **Ratings
                    of Securities**
                
                **Securities**
                
                **S&P**
                
                **Moody’s**
                
                **Fitch****FirstEnergy**
                
                Senior
                    unsecured
                
                BBB-
                
                Baa3
                
                BBB-**OE**
                
                Senior
                    unsecured
                
                BBB-
                
                Baa2
                
                BBBPreferred
                    stock
                
                BB+
                
                Ba1
                
                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+Preferred
                    stock
                
                BB+
                
                Ba1
                
                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
          July 1,
          2005, TE redeemed all of its 1,200,000 outstanding shares of 7.00% Series
          A
          preferred stock at $25.00 per share, plus accrued dividends to the date
          of
          redemption. TE also repurchased $37 million of pollution control revenue
          bonds
          on September 1, 2005, with the intent to remarket them by the end
          of the
          first quarter of 2006.
 
 
 
 49
 ***Cash
          Flows From Investing Activities***
 
 Net
          cash flows used
          for investing activities resulted principally from property additions.
          Regulated
          services expenditures for property additions primarily include expenditures
          supporting the distribution of electricity. Capital expenditures by the
          power
          supply management services segment are principally generation-related.
          The
          following table summarizes the investment activities for the three months
          and
          nine months ended September 30, 2005 and 2004 by FirstEnergy’s regulated
          services, power supply management services and other
          segments:
 
 **Summary
                  of Cash Flows**
              
              **Property****Used
                  for Investing Activities**
              
              **Additions**
              
              **Investments**
              
              **Other**
              
              **Total****Sources
                  (Uses)**
              
              ***(In
                  millions)*****Three
                  Months Ended September 30, 2005**Regulated
                  services
              
              $
              (207
              )
              $
              (17
              )
              $
              2
              
              $
              (222
              )Power
                  supply
                  management services
              
              
              (79
              )
              
              1
              
              
              -
              
              
              (78
              )Other
              
              
              (1
              )
              
              -
              
              
              1
              
              
              -Reconciling
                  items
              
              
              (7
              )
              
              (9
              )
              
              5
              
              
              (11
              )Total
              
              $
              (294
              )
              $
              (25
              )
              $
              8
              
              $
              (311
              )**Three
                  Months Ended September 30, 2004**Regulated
                  services
              
              $
              (157
              )
              $
              242
              
              $
              (69
              )
              $
              16Power
                  supply
                  management services
              
              
              (46
              )
              
              (11
              )
              
              -
              
              
              (57
              )Other
              
              
              (1
              )
              
              -
              
              
              (2
              )
              
              (3
              )Reconciling
                  items
              
              
              (7
              )
              
              10
              
              
              84
              
              
              87Total
              
              $
              (211
              )
              $
              241
              
              $
              13
              
              $
              43
 
 
 **Summary
                of Cash Flows**
              
              **Property****Used
                  for Investing Activities**
              
              **Additions**
              
              **Investments**
              
              **Other**
              
              **Total****Sources
                (Uses)**
              
              ***(In
                  millions)*****Nine
                  Months Ended September 30, 2005**Regulated
                  services
              
              $
              (506
              )
              $
              (13
              )
              $
              (5
              )
              $
              (524
              )Power
                  supply
                  management services
              
              
              (226
              )
              
              -
              
              
              -
              
              
              (226
              )Other
              
              
              (6
              )
              
              19
              
              
              (18
              )
              
              (5
              )Reconciling
                  items
              
              
              (18
              )
              
              (9
              )
              
              5
              
              
              (22
              )Total
              
              $
              (756
              )
              $
              (3
              )
              $
              (18
              )
              $
              (777
              )**Nine
                  Months Ended September 30, 2004**Regulated
                  services
              
              $
              (377
              )
              $
              196
              
              $
              (76
              )
              $
              (257
              )Power
                  supply
                  management services
              
              
              (149
              )
              
              (14
              )
              
              -
              
              
              (163
              )Other
              
              
              (3
              )
              
              173
              
              
              2
              
              
              172Reconciling
                  items
              
              
              (17
              )
              
              31
              
              
              65
              
              
              79Total
              
              $
              (546
              )
              $
              386
              
              $
              (9
              )
              $
              (169
              )
 
 Net
          cash used for
          investing activities was $311 million in the third quarter of 2005 compared
          to
          $43 million of cash provided from investing activities in the same period
          of
          2004. The change was primarily due to an $83 million increase in property
          additions and the absence in 2005 of $278 million in cash proceeds from
          certificates of deposit (released collateral) received in the third quarter
          of
          2004. Net cash used for investing activities increased by $608 million
          in the
          first nine months of 2005 compared to the same period of 2004. The increase
          principally resulted from a $210 million increase in property additions,
          lower
          proceeds from the sale of assets of $152 million and the absence in 2005
          of $278
          million of cash proceeds from certificates of deposit (released collateral)
          received in 2004.
 
 In
          the last quarter
          of 2005, capital requirements for property additions and capital leases
          are
          expected to be approximately $378 million. FirstEnergy and the Companies
          have
          additional requirements of approximately $312 million for maturing long-term
          debt during the remainder of 2005. These cash requirements are expected
          to be
          satisfied from internal cash and short-term credit arrangements.
 
 FirstEnergy’s
          capital spending for the period 2005-2007 is expected to be about $3.5
          billion
          (excluding nuclear fuel), of which $1.1 billion applies to 2005. Investments
          for
          additional nuclear fuel during the 2005-2007 periods are estimated to be
          approximately $285 million, of which approximately $59 million applies
          to 2005.
          During the same period, FirstEnergy’s nuclear fuel investments are expected to
          be reduced by approximately $282 million and $86 million respectively,
          as the
          nuclear fuel is consumed.
 
 50
  **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.
          Such agreements include contract guarantees, surety bonds, and LOCs. Some
          of the
          guaranteed contracts contain ratings contingent collateralization
          provisions.
 
 As
          of September 30,
          2005, the maximum potential future payments under outstanding guarantees
          and
          other assurances totaled $2.7 billion as summarized
          below:
 **Maximum****Guarantees
                  and Other Assurances**
              
              **Exposure*****(In
                  millions)***FirstEnergy
                  guarantees of subsidiaries:Energy
                  and
                  energy-related contracts(1)
              
              $
              785Other(2)
              
              
              5031,288Surety
                  bonds
              
              
              307Letters
                  of
                  credit(3)(4)
              
              
              1,055Total
                  Guarantees and Other Assurances
              
              $
              2,650(1)Issued
                  for a
                  one-year term, with a 10-day termination right by
                  FirstEnergy.(2)Issued
                  for
                  various terms.(3)Includes
                  $137
                  million issued for various terms under LOC capacity availableunder
                  FirstEnergy's revolving credit agreement and $299 million outstanding
                  insupport of pollution control revenue bonds issued with various
                  maturities.(4)Includes
                  approximately $194 million pledged in connection with the sale
                  andleaseback of Beaver Valley Unit 2 by CEI and TE, $291 million pledged
                  in
                  connectionwith
                  the sale and leaseback of Beaver Valley Unit 2 by OE and $134 million
                  pledgedin
                  connection with the sale and leaseback of Perry Unit 1 by
                  OE.
 
 FirstEnergy
          guarantees energy and energy-related payments of its subsidiaries involved
          in
          energy marketing activities - principally to facilitate normal
          physical transactions involving electricity, gas, emission allowances and
          coal.
          FirstEnergy also provides guarantees to various providers of subsidiary
          financing principally for the acquisition of property, plant and equipment.
          These agreements legally obligate FirstEnergy and its subsidiaries to fulfill
          the obligations of those subsidiaries directly involved in 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-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. The following
          table
          summarizes collateral provisions in effect as of September 30,
          2005:
 **Total**
                
                **Collateral
                    Paid**
                
                **Remaining****Collateral
                    Provisions**
                
                
                **Exposure**
                
                **Cash**
                
                **LOC**
                
                **Exposure*****(In
                    millions)***Credit
                    rating
                    downgrade
                
                
                
                $
                445
                
                $
                213
                
                $
                18
                
                $
                214Adverse
                    event
                
                
                
                
                77
                
                
                -
                
                
                5
                
                
                72Total
                
                
                
                $
                522
                
                $
                213
                
                $
                23
                
                $
                286
 
 As
          a result of
          S&P's credit rating upgrade described above, $109 million of cash collateral
          was returned to FirstEnergy in October 2005.
 
 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.
  51
  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 provided an LOC ($47 million as of September 30,
          2005,
          which is included in the caption “Other” in the above table of Guarantees and
          Other Assurances), which is renewable and declines yearly based upon the
          senior
          outstanding debt of TEBSA. The LOC was reduced to $36 million on October
          15,
          2005.
 
 **OFF-BALANCE
          SHEET ARRANGEMENTS**
 
 FirstEnergy
          has
          obligations that are not included on its Consolidated Balance Sheet related
          to
          the sale and leaseback arrangements involving Perry Unit 1, 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, 2005.
 
 FirstEnergy
          has
          equity ownership interests in certain businesses that are accounted for
          under
          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 contractual obligations
          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 management oversight to risk management activities throughout
          the Company.
 
 ***Commodity
          Price Risk***
 
 FirstEnergy
          is
          exposed to price risk primarily due to fluctuating electricity, natural
          gas,
          coal, nuclear fuel, emission allowance prices and energy transmission.
          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
          and, to a much lesser extent, for trading purposes. All derivatives that
          fall
          within the scope of SFAS 133 must be recorded at their fair market value
          and
          marked to market. The majority of FirstEnergy’s derivative hedging contracts
          qualify for the normal purchases and normal sales exception under SFAS
          133 and
          are therefore excluded from the table below. Of those contracts not exempt
          from
          such treatment, most are non-trading contracts that do not qualify for
          hedge
          accounting treatment. The change in the fair value of commodity derivative
          contracts related to energy production during the third quarter and first
          nine
          months of 2005 is summarized in the following table:
 **Three
                  Months Ended**
              
              **Nine
                  Months Ended****Increase
                  (Decrease) in the Fair Value**
              
              **September
                  30, 2005**
              
              **September
                  30, 2005****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
              
              $
              55
              
              $
              (2
              )
              $
              53
              
              $
              62
              
              $
              2
              
              $
              64New
                  contract
                  when entered
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Additions/change
                  in value of existing contracts
              
              
              (3
              )
              
              3
              
              
              -
              
              
              (4
              )
              
              5
              
              
              1Change
                  in
                  techniques/assumptions
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Settled
                  contracts
              
              
              -
              
              
              -
              
              
              -
              
              
              (7
              )
              
              -
              
              
              (7
              )Sale
                  of
                  retail natural gas contracts
              
              
              -
              
              
              -
              
              
              -
              
              
              1
              
              
              (6
              )
              
              (5
              )Outstanding
                  net asset at end of period(1)
              
              $
              52
              
              $
              1
              
              $
              53
              
              $
              52
              
              $
              1
              
              $
              53**Non-commodity
                  Net Assets at End of Period:**Interest
                  rate
                  swaps(2)
              
              
              -
              
              
              (10
              )
              
              (10
              )
              
              -
              
              
              (10
              )
              
              (10
              )**Net
                  Assets - Derivative Contracts at End of Period**
              
              $
              52
              
              $
              (9
              )
              $
              43
              
              $
              52
              
              $
              (9
              )
              $
              43**Impact
                  of Changes in Commodity Derivative Contracts****(3)**Income
                  Statement effects (pre-tax)
              
              $
              (4
              )
              $
              -
              
              $
              (4
              )
              $
              (4
              )
              $
              -
              
              $
              (4
              )Balance
                  Sheet
                  effects:Other
                  comprehensive income (pre-tax)
              
              $
              -
              
              $
              3
              
              $
              3
              
              $
              -
              
              $
              (1
              )
              $
              (1
              )Regulatory
                  liability
              
              $
              1
              
              $
              -
              
              $
              1
              
              $
              (6
              )
              $
              -
              
              $
              (6
              )(1)Includes
                  $55 million in non-hedge commodity derivative contracts which are
                  offset
                  by a regulatory liability.(2)Interest
                  rate
                  swaps are treated as cash flow or fair value hedges. (See Interest
                  Rate
                  Swap Agreements - Fair Value Hedges and ForwardStarting
                  Swap Agreements - Cash Flow Hedges)(3)Represents
                  the change in value of existing contracts, settled contracts and
                  changes
                  in techniques/assumptions.
   52
  Derivatives
          are
          included on the Consolidated Balance Sheet as of September 30, 2005
          as
          follows:
 **Balance
                  Sheet Classification**
              
              **Non-Hedge**
              
              **Hedge**
              
              **Total*****(In
                  millions)*****Current**-Other
                  assets
              
              $
              -
              
              $
              39
              
              $
              39Other
                  liabilities
              
              
              (1
              )
              
              (39
              )
              
              (40
              )**Non-Current**-Other
                  deferred charges
              
              
              56
              
              
              5
              
              
              61Other
                  noncurrent liabilities
              
              
              (3
              )
              
              (14
              )
              
              (17
              )Net
                  assets
              
              $
              52
              
              $
              (9
              )
              $
              43
 
  The
          valuation of
          derivative commodity 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 derivative contracts
          by year
          are summarized in the following table:
 **Sources
                  of Information -****Fair
                  Value by Contract Year**
              
              **2005**(1)
              
              **2006**
              
              **2007**
              
              **2008**
              
              **2009**
              
              **Thereafter**
              
              **Total*****(In
                  millions)***Prices
                  actively quoted(2)
              
              $
              (3
              )
              $
              (3
              )
              $
              (2
              )
              $
              -
              
              $
              -
              
              $
              -
              
              $
              (8
              )Other
                  external sources(3)
              
              
              19
              
              
              7
              
              
              10
              
              
              -
              
              
              -
              
              
              -
              
              
              36Prices
                  based
                  on models
              
              
              -
              
              
              -
              
              
              -
              
              
              9
              
              
              8
              
              
              8
              
              
              25Total(4)
              
              $
              16
              
              $
              4
              
              $
              8
              
              $
              9
              
              $
              8
              
              $
              8
              
              $
              53(1)For
                  the
                  last quarter of 2005.(2)Exchange
                  traded.(3)Broker
                  quote sheets.(4)Includes
                  $55 million in non-hedge commodity derivative contracts which are
                  offset
                  by a regulatory liability.
 
 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 both FirstEnergy's trading and nontrading 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, 2005.
          Based on
          derivative contracts held as of September 30, 2005, an adverse 10%
          change
          in commodity prices would decrease net income by approximately $1 million
          for
          the next twelve months.
 
 ***Interest
          Rate Swap Agreements - Fair Value Hedges***
 
 FirstEnergy
          utilizes fixed-to-floating interest rate swap agreements as part of its
          ongoing
          effort to manage the interest rate risk of its debt portfolio. These derivatives
          are treated as fair value hedges of fixed-rate, long-term debt issues - protecting 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
          and
          interest payment dates match those of the underlying obligations. During
          the
          third quarter of 2005, FirstEnergy executed no new fixed-for-floating interest
          rate swaps and unwound swaps with a total notional amount of $350 million
          (see
          Note 7). As of September 30, 2005, the debt underlying the $1.05
          billion
          outstanding notional amount of interest rate swaps had a weighted average
          fixed
          interest rate of 5.66%, which the swaps have effectively converted to a
          current
          weighted average variable interest rate of 5.23%.
 
 53
   **September
                  30, 2005**
              
              **December
                  31, 2004****Notional**
              
              **Maturity**
              
              **Fair**
              
              **Notional**
              
              **Maturity**
              
              **Fair****Interest
                  Rate Swaps**
              
              **Amount**
              
              **Date**
              
              **Value**
              
              **Amount**
              
              **Date**
              
              **Value*****(Dollars
                  in millions)***Fixed
                  to
                  Floating Rate
              
              $
              -
              
              
              2006
              
              $
              -
              
              $
              200
              
              
              2006
              
              $
              (1
              )(Fair
                  value
                  hedges)
              
              
              100
              
              
              2008
              
              
              (3
              )
              
              100
              
              
              2008
              
              
              (1
              )50
              
              
              2010
              
              
              -
              
              
              100
              
              
              2010
              
              
              150
              
              
              2011
              
              
              -
              
              
              100
              
              
              2011
              
              
              2450
              
              
              2013
              
              
              -
              
              
              400
              
              
              2013
              
              
              4-
              
              
              2014
              
              
              -
              
              
              100
              
              
              2014
              
              
              2150
              
              
              2015
              
              
              (7
              )
              
              150
              
              
              2015
              
              
              (7
              )150
              
              
              2016
              
              
              2
              
              
              200
              
              
              2016
              
              
              1-
              
              
              2018
              
              
              -
              
              
              150
              
              
              2018
              
              
              5-
              
              
              2019
              
              
              -
              
              
              50
              
              
              2019
              
              
              2100
              
              
              2031
              
              
              (4
              )
              
              100
              
              
              2031
              
              
              (4
              )$
              1,050
              
              
              
              
              $
              (12
              )
              $
              1,650
              
              
              
              
              $
              4
 
 ***Forward
          Starting Swap Agreements - Cash Flow Hedges***
 
 During
          the third
          quarter, FirstEnergy entered into several forward starting swap agreements
          (forward swap) in order to hedge a portion of the consolidated interest
          rate
          risk associated with the planned issuance of fixed-rate, long-term debt
          securities for one or more of its consolidated entities in the fourth quarter
          of
          2006. 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. As of September 30, 2005, the forward swaps had a fair
          value of
          $2 million.
 
 ***Equity
          Price Risk***
 
 Included
          in nuclear
          decommissioning trusts are marketable equity securities carried at their
          market
          value of approximately $1.038 billion and $951 million as of September 30,
          2005 and December 31, 2004, respectively. A hypothetical 10% decrease
          in
          prices quoted by stock exchanges would result in a $104 million reduction
          in
          fair value as of September 30, 2005.
 
 **CREDIT
          RISK**
  Credit
          risk is the
          risk of an obligor’s failure to meet the terms of any 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, 2005, the largest credit concentration was
          with one party, currently rated investment grade that represented 8% of
          FirstEnergy’s total credit risk. Within its unregulated energy subsidiaries, 99%
          of credit exposures, net of collateral and reserves, were with investment-grade
          counterparties as of September 30, 2005.
 
 **Outlook**
 
 ***State
          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;
  54
 ·
                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
            EUOCs
            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. All regulatory assets are expected to be recovered from customers
            under the Companies' respective transition and regulatory plans. Based
            on those
            plans, the Companies continue to bill and collect cost-based rates for
            their
            transmission and distribution services, which remain regulated; accordingly,
            it
            is appropriate that the Companies continue the application of SFAS 71
            to those
            operations.
 **September
                  30,**
              
              **December
                  31,**
              
              **Increase****Regulatory
                  Assets***
              
              **2005**
              
              **2004**
              
              **(Decrease)*****(In
                  millions)***OE
              
              $
              845
              
              $
              1,116
              
              $
              (271
              )CEI
              
              
              889
              
              
              959
              
              
              (70
              )TE
              
              
              310
              
              
              375
              
              
              (65
              )JCP&L
              
              
              2,311
              
              
              2,176
              
              
              135Met-Ed
              
              
              572
              
              
              693
              
              
              (121
              )Penelec
              
              
              99
              
              
              200
              
              
              (101
              )ATSI
              
              
              20
              
              
              13
              
              
              7Total
              
              $
              5,046
              
              $
              5,532
              
              $
              (486
              )*Penn
                  had net
                  regulatory liabilities of approximately $48 million and $18 million
                included
                  in Noncurrent Liabilities on the Consolidated Balance Sheets as
                  of
                September
                  30, 2005 and December 31, 2004, respectively.
 
 Regulatory
        assets
        by source are as follows:
 
 **September
                  30,**
              
              **December
                  31,**
              
              **Increase****Regulatory
                  Assets by Source**
              
              **2005**
              
              **2004**
              
              **(Decrease)*****(In
                  millions)***Regulatory
                  transition costs
              
              
              $
              4,169
              
              $
              4,889
              
              $
              (720
              )Customer
                  shopping incentives
              
              
              
              826
              
              
              612
              
              
              214Customer
                  receivables for future income taxes
              
              
              
              289
              
              
              246
              
              
              43Societal
                  benefits charge
              
              
              
              18
              
              
              51
              
              
              (33
              )Loss
                  on
                  reacquired debt
              
              
              
              83
              
              
              89
              
              
              (6
              )Employee
                  postretirement benefit costs
              
              
              
              57
              
              
              65
              
              
              (8
              )Nuclear
                  decommissioning, decontaminationand
                  spent
                  fuel disposal costs
              
              
              
              (172
              )
              
              (169
              )
              
              (3
              )Asset
                  removal
                  costs
              
              
              
              (366
              )
              
              (340
              )
              
              (26
              )Property
                  losses and unrecovered plant costs
              
              
              
              34
              
              
              50
              
              
              (16
              )MISO
                  transmission costs
              
              
              
              52
              
              
              -
              
              
              52JCP&L
                  reliability costs
              
              
              
              26
              
              
              -
              
              
              26Other
              
              
              
              30
              
              
              39
              
              
              (9
              )Total
              
              
              $
              5,046
              
              $
              5,532
              
              $
              (486
              )
 
 ***Reliability
          Initiatives***
  FirstEnergy
          is
          proceeding with the implementation of the recommendations regarding enhancements
          to regional reliability 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, 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
          the
          Energy Policy Act of 2005 that could require additional, material expenditures.
          Finally, the PUCO is continuing to review FirstEnergy's filing that addressed
          upgrades to control room computer hardware and software and enhancements
          to the
          training of control room operators, before determining the next steps,
          if any,
          in the proceeding.
 55
 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. On March 29,
          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
          a Special
          Reliability Master 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 Ratepayer Advocate to discuss reliability improvements. JCP&L
          continues to file compliance reports reflecting activities associated with
          the
          MOU and Stipulation.
 
 The
          Energy Policy
          Act of 2005 provides for the creation of an ERO to establish and enforce
          reliability standards for the bulk power system, subject to FERC review.
          On
          September 1, 2005, the FERC issued a Notice of Proposed Rulemaking
          to
          establish certification requirements for the ERO, as well as regional entities
          envisioned to assume monitoring and compliance responsibility for the new
          reliability standards. The FERC expects to adopt a final rule on or before
          February 2006 regarding certification requirements for the ERO and regional
          entities.
 
 The
          NERC is
          expected to reorganize its structure to meet the FERC’s certification
          requirements for the ERO. Following adoption of the final rule, the NERC
          will be
          required to make a filing with the FERC to obtain certification as the
          ERO. The
          proposed rule also provides for regional reliability organizations designed
          to
          replace the current regional councils. 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 ECAR, Mid-Atlantic
          Area Council, and Mid-American Interconnected Network reliability
          councils have signed an MOU designed to consolidate their regions into
          a new
          regional reliability organization known as ReliabilityFirst Corporation.
          Their
          intent is to file and obtain certification under the final rule as a “regional
          entity”. All of FirstEnergy’s facilities would be located within the
          ReliabilityFirst region.
 
 On
          a parallel path,
          the NERC is establishing working groups to develop reliability standards
          to be
          filed for approval with the FERC following the NERC’s certification as an ERO.
          These reliability standards are expected to build on the current NERC Version
          0
          reliability standards. It is expected that the proposed reliability standards
          will be filed with the FERC in early 2006.
 
 The
          impact of this
          effort on FirstEnergy is unclear. FirstEnergy believes that it is in compliance
          with all current NERC reliability standards. However, it is expected that
          the
          FERC will adopt stricter reliability standards than those contained in
          the
          current NERC Version 0 standards. The financial impact of complying with
          the new
          standards cannot be determined at this time. However, the Energy Policy
          Act of
          2005 requires that all prudent costs incurred to comply with the new reliability
          standards be recovered in rates.
 
 See
          Note 14 to the
          consolidated financial statements for a more detailed discussion of reliability
          initiatives, including actions by the PPUC, that impact Met-Ed, Penelec
          and
          Penn.
 
 ***Ohio***
 
 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 competitive
          bid
          process. The RSP was filed by the Ohio Companies to establish generation
          service
          rates beginning January 1, 2006, in response to PUCO 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 this proceeding as well as the associated entries on rehearing. On
          September 28, 2005, the Ohio Supreme Court heard oral argument on
          the
          appeals.
 
 On
          May 27,
          2005, the Ohio Companies filed an application with the PUCO to establish
          a GCAF
          rider under the RSP. The application seeks to implement recovery of increased
          fuel costs from 2006 through 2008 applicable to the Ohio Companies' retail
          customers through a tariff rider to be implemented January 1, 2006.
          The
          application reflects projected increases in fuel costs in 2006 compared
          to 2002
          baseline costs. The new rider, after adjustments made in testimony, is
          seeking
          to recover all costs above the baseline (approximately $88 million in 2006).
          Various parties including the OCC have intervened in this case and the
          case has
          been consolidated with the RCP application discussed below.
  56
 On
          September 9, 2005, the Ohio Companies filed an application with
          the PUCO
          that, if approved, would supplement their existing RSP with an RCP. On
          September 27, 2005, the PUCO granted FirstEnergy's motion to consolidate
          the GCAF rider application with the RCP proceedings and set hearings for
          the
          consolidated cases to begin November 29, 2005. The RCP is designed
          to
          provide customers with more certain rate levels than otherwise available
          under
          the RSP during the plan period. Major provisions of the RCP
          include:
 
 · Maintain
          the
          existing level of base distribution rates through December 31, 2008
          for OE
          and TE, and
 April 30,
          2009
          for CEI;
 
 · Defer
          and
          capitalize 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;
 
 · Adjust
          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;
 
 · Reduce
          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
 
 · Recover
          increased
          fuel costs 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
          and OE, TE, and CEI may defer and capitalize increased fuel costs above
          the
 amount
          collected
          through the fuel recovery mechanism.
 
 Under
          provisions of
          the RSP, the PUCO may require the Ohio Companies to undertake, no more
          often
          than annually, a competitive bid process to secure generation for the years
          2007
          and 2008. On July 22, 2005, FirstEnergy filed a competitive bid
          process for
          the period beginning in 2007 that is similar to the competitive bid process
          approved by the PUCO for the Ohio Companies in 2004 which resulted in the
          PUCO
          accepting no bids. Any acceptance of future competitive bid results would
          terminate the RSP pricing, with no accounting impacts to the RSP, and not
          until
          twelve months after the PUCO authorizes such termination. On September 28,
          2005, the PUCO issued an Entry that essentially approved the Ohio Companies'
          filing but delayed the proposed timing of the competitive bid process by
          four
          months, calling for the auction to be held on March 21, 2006.
 
 See
          Note 14 to the
          consolidated financial statements for further details and a complete discussion
          of regulatory matters in Ohio.
 
 ***Pennsylvania***
 
 In
          accordance with
          PPUC directives, Met-Ed and Penelec have been negotiating with interested
          parties in an attempt to resolve the merger savings issues that are the
          subject
          of remand from the Commonwealth Court. Met-Ed’s and Penelec’s combined portion
          of total merger savings is estimated to be approximately $31.5 million.
          On
          April 13, 2005, the Commonwealth Court issued an interim order in
          the
          remand proceeding that the parties should report the status of the negotiations
          to the PPUC with a copy to the ALJ. The parties exchanged settlement proposals
          in May and June 2005 and continue to have settlement discussions.
 
 Met-Ed
          and Penelec
          purchase a portion of their PLR requirements from FES through a wholesale
          power
          sales agreement. The PLR sale is automatically extended for each successive
          calendar year unless any party elects to cancel the agreement by November 1
          of the preceding year. Under the terms of the wholesale 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
          NUG contracts and other power contracts with nonaffiliated third party
          suppliers. This 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. Met-Ed and
          Penelec
          are authorized to defer differences between NUG contract costs and current
          market prices. On
          November 1,
          2005, FES and the other parties to the wholesale power agreement amended
          the
          agreement to provide FES the right over the next year to terminate the
          agreement
          at any time upon 60 days notice.If
          the wholesale
          power agreement were terminated, Met-Ed and Penelec would need to satisfy
          the
          applicable portion of their PLR obligations from other sources at prevailing
          prices, which are likely to be higher than the current price charged by
          FES
          under the agreement and, as a result, Met-Ed’s and Penelec’s purchased power
          costs could materially increase.
 
 On
          January 12,
          2005, Met-Ed and Penelec filed, before the PPUC, a request for deferral
          of
          transmission-related costs beginning January 1, 2005, estimated
          to be
          approximately $8 million per month. The OCA, OSBA, OTS, MEIUG, PICA, Allegheny
          Electric Cooperative and Pennsylvania Rural Electric Association have all
          intervened in the case. To date no hearing schedule has been established,
          and
          neither company has yet implemented deferral accounting for these
          costs.
 
 57
 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 is recommending that the Request for Proposal process cover
          the
          period of January 1, 2007 through May 31, 2008. Under Pennsylvania's
          electric competition law, Penn is required to secure generation supply
          for
          customers who do not choose alternative suppliers for their
          electricity.
 
 See
          Note 14 to the
          consolidated financial statements for further details and a complete discussion
          of regulatory matters in Pennsylvania.
 
 ***New
          Jersey***
 
 The
          2003 NJBPU
          decision on JCP&L's base electric rate proceeding (Phase I order) disallowed
          certain regulatory assets and provided for an interim return on equity
          of 9.5%
          on JCP&L's rate base. The Phase I Order also provided for a Phase II
          proceeding in which the NJBPU would review whether JCP&L is in compliance
          with current service reliability and quality standards and determine whether
          the
          expenditures and projects undertaken by JCP&L to increase its system
          reliability are prudent and reasonable for rate recovery. Depending on
          its
          assessment of JCP&L's service reliability, the NJBPU could have increased
          JCP&L’s return on equity to 9.75% or decreased it to 9.25%. On
          August 15, 2003 and June 1, 2004, JCP&L filed with the NJBPU an
          interim motion and a supplemental and amended motion for rehearing and
          reconsideration of the Phase I Order, respectively. On July 7, 2004,
          the
          NJBPU granted limited reconsideration and rehearing on the following issues:
          (1)
          deferred cost disallowances; (2) the capital structure including the rate
          of
          return; (3) merger savings, including amortization of costs to achieve
          merger
          savings; and (4) decommissioning costs.
 
 On
          July 16,
          2004, JCP&L filed the Phase II petition and testimony with the NJBPU,
          requesting an increase in base rates of $36 million for the recovery of
          system
          reliability costs and a 9.75% return on equity. The filing also requested
          an
          increase to the MTC deferred balance recovery of approximately $20 million
          annually.
 
 On
          May 25,
          2005, the NJBPU approved two stipulated settlement agreements. The first
          stipulation between JCP&L and the NJBPU staff resolves all of the issues
          associated with JCP&L's motion for reconsideration of the 2003 NJBPU order
          Phase I Order. The second stipulation between JCP&L, the NJBPU staff and the
          Ratepayer Advocate resolves all of the issues associated with JCP&L's Phase
          II proceeding. The stipulated settlements provide for, among other things,
          the
          following:
 
 · An
          annual increase
          in distribution revenues of $23 million, effective June 1, 2005,
          associated
          with the
 Phase I
          Order
          reconsideration;
 
 · An
          annual increase
          in distribution revenues of $36 million, effective June 1, 2005,
          related to
          JCP&L's
 Phase II
          Petition;
 
 · An
          annual reduction
          in both rates and amortization expense of $8 million, effective June 1,
          2005, in
 anticipation
          of an
          NJBPU order regarding JCP&L's request to securitize up to $277 million of
          its deferred
 cost
          balance;
 
 · An
          increase in
          JCP&L's authorized return on common equity from 9.5% to 9.75%;
          and
 
 · A
          commitment by
          JCP&L to maintain a target level of customer service reliability with a
          reduction in
 JCP&L's
          authorized return on common equity from 9.75% to 9.5% if the target is
          not met
          for two
 consecutive
          quarters.
          The authorized return on common equity would then be restored to 9.75%
          if
          the
 target
          is met for two
          consecutive quarters.
 
 The
          Phase II
          stipulation included an agreement that the distribution revenue increase
          also
          reflects a three-year amortization of JCP&L's one-time service reliability
          improvement costs incurred in 2003-2005. This resulted in the creation
          of a
          regulatory asset associated with accelerated tree trimming and other reliability
          costs which were expensed in 2003 and 2004. The establishment of the new
          regulatory asset of approximately $28 million resulted in an increase to
          net
          income of approximately $16 million ($0.05 per share of FirstEnergy common
          stock) in the second quarter of 2005.
 
 JCP&L
          sells all
          self-supplied energy (NUGs and owned generation) to the wholesale market
          with
          offsetting credits to its deferred energy balance with the exception of
          300 MW
          from JCP&L's NUG committed supply currently being used to serve BGS
          customers pursuant to NJBPU order for the period June 1, 2005 through May
          31,
          2006. New BGS tariffs reflecting the results of a February 2005 auction
          for the
          BGS supply became effective June 1, 2005. On July 1, 2005,
          JCP&L
          filed its BGS procurement proposals for post transition year four. The
          auction
          is scheduled to take place in February 2006 for the annual supply period
          beginning June 1, 2006.
  58
 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 Ratepayer Advocate filed comments on
        February 28, 2005. On March 18, 2005, JCP&L filed a response to
        those comments. A schedule for further proceedings has not yet been
        set.
 See
          Note 14 to the
          consolidated financial statements for further details and a complete discussion
          of regulatory matters in New Jersey.
 
 ***Transmission***
  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 seeks recovery of these costs beginning January 1,
          2006.
          At the time of filing the application, these costs were estimated to be
          approximately $30 million per year; however, the Ohio Companies anticipate
          that
          this amount will increase. 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 Ohio Companies reached a settlement
          with OCC, PUCO staff, Industrial Energy Users - Ohio and OPAE. The only
          other
          party in this proceeding, Dominion Retail, Inc., agreed not to oppose the
          settlement. This settlement, which was filed with the PUCO on July 22,
          2005, provides for the rider recovery requested by the Ohio Companies,
          with
          carrying charges applied in the subsequent year’s rider for any over or under
          collection while the then-current rider is in effect. The PUCO approved
          the
          settlement stipulation on August 31, 2005. The incremental Transmission
          and
          Ancillary service revenues expected to be recovered from January through
          June
          2006 are approximately $61.2 million. This value includes the recovery
          of the
          2005 deferred MISO expenses as described below. In May 2006, the Ohio Companies
          will file a modification to the rider which will determine revenues from
          July
          2006 through June 2007.
 
 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 the
          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 31, 2004 was denied. The PUCO also authorized the Ohio
          Companies
          to accrue carrying charges on the deferred balances. An application filed
          with
          the PUCO to recover these deferred charges over a five-year period through
          the
          rider, beginning in 2006, was approved in a PUCO order issued on August 31,
          2005 approving the stipulation referred to above. The OCC, OPAE and the
          Ohio
          Companies each filed applications for rehearing. The Ohio Companies sought
          authority to defer the transmission and ancillary service related costs
          incurred
          during the period October 1, 2003 through December 29, 2004,
          while
          both OCC and OPAE sought to have the PUCO deny deferral of all costs. On
          July 6, 2005, the PUCO denied the Ohio Companies' and OCC’s applications
          and, at the request of the Ohio Companies, struck as untimely OPAE’s
          application. The OCC filed a notice of appeal with the Ohio Supreme Court
          on
          August 31, 2005. On September 30, 2005, in accordance with appellate
          procedure, the PUCO filed with the Ohio Supreme Court the record in this
          case.
          The Companies' brief will be due thirty days after the OCC files its brief,
          which, absent any time extensions, must be filed no later than November
          9,
          2005.
 
 On
          January 31,
          2005, certain PJM transmission owners made three filings 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. Second, the
          FERC
          approved the proposed Schedule 12 rate harmonization. Third, the FERC accepted
          the proposed formula rate, subject to referral and hearing procedures.
          On
          September 30, 2005, the PJM transmission owners filed a request
          for
          rehearing of the May 31, 2005 order. The rate design and formula
          rate
          filings continue to be litigated before the FERC. The outcome of these
          two cases
          cannot be predicted.
 
 ***Environmental
          Matters***
  The
          Companies
          accrue environmental liabilities only when they conclude that it is probable
          that they have an obligation for such costs and can reasonably estimate
          the
          amount of such costs. Unasserted claims are reflected in the Companies’
          determination of environmental liabilities and are accrued in the period
          that
          they are both probable and reasonably estimable.
 59
  FirstEnergy
          plans
          to issue a report regarding its response to air emission requirements.
          FirstEnergy expects to complete the report by December 1,
          2005.
 
 *National
          Ambient Air Quality Standards*
  In
          July 1997, the
          EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS
          for fine
          particulate matter. On March 10, 2005, the EPA finalized the "Clean
          Air
          Interstate Rule" 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 nonattainment 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 regulation 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 )
          in all cases from
          the 2003 levels. The Companies’ Michigan, Ohio and Pennsylvania fossil-fired
          generation facilities will be subject to the caps on SO 2 and NO x emissions, whereas
          their New Jersey fossil-fired generation facilities 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 the Companies operate 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. On March 14, 2005,
          the EPA
          finalized the "Clean Air Mercury Rule," 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
          the CAIR
          and the Clean Air Mercury rule 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.
 
 *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 is owned 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, which is in the form of a
          Consent
          Decree, was approved by the Court on July 11, 2005, requires OE
          and Penn to
          reduce NOx and SO 2 emission
          at the W.
          H. Sammis Plant and other coal-fired plants through the installation of
          pollution control devices. Capital expenditures necessary to meet those
          requirements are currently estimated to be $1.5 billion (the primary portion
          of
          which is expected to be spent in the 2008 to 2011 time period). As disclosed
          in
          FirstEnergy's Form 8-K dated August 26, 2005, FGCO entered into an agreement
          with Bechtel Power Corporation (Bechtel), under which Bechtel will engineer,
          procure, and construct air quality control systems for the reduction of
          sulfur
          dioxide emissions. 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 payable by OE and Penn of $7.8 million and $0.7 million,
          respectively. OE and Penn also recognized liabilities of $9.2 million and
          $0.8
          million, respectively, for probable future cash contributions toward
          environmentally beneficial projects during the first quarter of
          2005.
 60
 *Climate
          Change*
 
 In
          December 1997,
          delegates to the United Nations' climate summit in Japan adopted an agreement,
          the Kyoto Protocol (Protocol), to address global warming by reducing the
          amount
          of man-made greenhouse gases emitted by developed countries by 5.2% from
          1990
          levels between 2008 and 2012. The United States signed the 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 greenhouse
          gas
          intensity - the ratio of emissions to economic output - by 18 percent through
          2012. The Energy Policy Act of 2005 established a Committee on Climate
          change
          Technology to coordinate federal climate change activities and promote
          the
          development and deployment of GHG reducing technologies.
 
 The
          Companies
          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 the Companies is lower than many
          regional competitors due to the Companies' 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, 2005, based on estimates of the total costs of cleanup,
          the
          Companies' proportionate responsibility for such costs and the financial
          ability
          of other nonaffiliated 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 $64 million (JCP&L - $46.8 million, CEI - $2.3 million, TE - $0.2 million,
          Met-Ed - $0.1 million and
          other - $14.6 million)
          have been accrued through September 30, 2005.
 
 See
          Note 13(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 FirstEnergy's normal business operations pending against FirstEnergy
          and its subsidiaries. The other material items not otherwise discussed
          above are
          described below.
 
 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 concludes, 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 website (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 also is proceeding with
          the
          implementation of the recommendations regarding enhancements to regional
          reliability 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, and therefore FirstEnergy has not accrued a liability as of
          September 30, 2005 for any expenditures in excess of those actually
          incurred through that date. FirstEnergy notes, however, that the FERC or
          other
          applicable government agencies and reliability coordinators may take a
          different
          view as to recommended enhancements or may recommend additional enhancements
          in
          the future that could require additional, material expenditures. Finally,
          the
          PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to
          control room computer hardware and software and enhancements to the training
          of
          control room operators, before determining the next steps, if any, in the
          proceeding.
 61
  FirstEnergy
          companies also are defending six separate complaint cases before the PUCO
          relating to the August 14, 2003 power outage. Two such cases were originally
          filed in Ohio State courts but subsequently dismissed for lack of subject
          matter
          jurisdiction and further appeals were unsuccessful. In both such 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. Of the four other pending PUCO complaint cases, three were
          filed by
          various insurance carriers either in their own name or as subrogees in
          the name
          of their insured. In each such case, the carriers seek reimbursement against
          various FirstEnergy companies (and, in one case, against PJM, MISO and
          American
          Electric Power Co. as well) for claims they paid to their insureds allegedly
          due
          to 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 fourth
          case
          involves the claim of a non-customer seeking reimbursement for losses incurred
          when its store was burglarized on August 14, 2003. In addition to these
          six
          cases, the Ohio Companies were named as respondents in a regulatory proceeding
          that was initiated at the PUCO in response to complaints alleging failure
          to
          provide reasonable and adequate service stemming primarily from the
          August 14, 2003 power outages. No estimate of potential liability
          has been
          undertaken for any of these cases.
 
 One
          complaint was
          filed on August 25, 2004 against FirstEnergy in the New York State Supreme
          Court. In this case, several plaintiffs in the New York City metropolitan
          area
          allege that they suffered damages as a result of the August 14,
          2003 power
          outages. None of the plaintiffs are customers of any FirstEnergy affiliate.
          FirstEnergy's motion to dismiss the case was granted on September 26,
          2005.
          Additionally, FirstEnergy Corp. was named in a complaint filed in Michigan
          State
          Court by an individual who is not a customer of any FirstEnergy company.
          A
          responsive pleading to this matter is not due until on or about December
          1,
          2005. No estimate of potential liability has been undertaken in this matter.
 
 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.
 
 FENOC
          received a
          subpoena in late 2003 from a grand jury sitting in the United States District
          Court for the Northern District of Ohio, Eastern Division requesting the
          production of certain documents and records relating to the inspection
          and
          maintenance of the reactor vessel head at the Davis-Besse Nuclear Power
          Station.
          On December 10, 2004, FirstEnergy received a letter from the United
          States
          Attorney's Office stating that FENOC is a target of the federal grand jury
          investigation into alleged false statements made to the NRC in the Fall
          of 2001
          in response to NRC Bulletin 2001-01. The letter also said that the designation
          of FENOC as a target indicates that, in the view of the prosecutors assigned
          to
          the matter, it is likely that federal charges will be returned against
          FENOC by
          the grand jury. On February 10, 2005, FENOC received an additional
          subpoena
          for documents related to root cause reports regarding reactor head degradation
          and the assessment of reactor head management issues at Davis-Besse. On May 11,
          2005, FENOC received a subpoena for documents related to outside meetings
          attended by Davis-Besse personnel on corrosion and cracking of control
          rod drive
          mechanisms and additional root cause evaluations.
 
 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 described
          above.
          FirstEnergy accrued $2.0 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.
 
 If
          it were
          ultimately determined that FirstEnergy or its subsidiaries have legal liability
          based on the events surrounding Davis-Besse, it could have a material adverse
          effect on FirstEnergy's or its subsidiaries' financial condition, results
          of
          operations and cash flows.
 
 Effective
          July 1, 2005 the NRC oversight panel for Davis-Besse was terminated
          and
          Davis-Besse returned to the standard NRC reactor oversight process. At
          that
          time, NRC inspections were augmented to include inspections to support
          the NRC's
          Confirmatory Order dated March 8, 2004 that was issued at the time
          of
          startup and to address an NRC White Finding related to the performance
          of the
          emergency sirens.
 
 62
  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. FENOC operates the Perry Nuclear
          Power
          Plant, which currently is owned and/or leased by OE, CEI, TE and Penn (however,
          see Note 17 regarding FirstEnergy’s pending intra-system generation asset
          transfers, which include owned portions of the plant). On
          April 4,
          2005, the NRC held a public forum 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" and met all cornerstone objectives although it remained under heightened
          NRC oversight since August 2004. During the public forum 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 May 26, 2005,
          the NRC
          held a public meeting to discuss its oversight of the Perry Plant. While
          the NRC
          stated that the plant continued to operate safely, the NRC also stated
          that the
          overall performance had not substantially improved since the heightened
          inspection was initiated. The NRC reiterated this conclusion in its mid-year
          assessment letter dated August 30, 2005. On September 28, 2005,
          the NRC
          sent a CAL to FENOC describing commitments that FENOC had made to improve
          the
          performance of Perry 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. 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. As a result, these matters
          could have a material adverse effect on FirstEnergy's or its subsidiaries'
          financial condition, results of operations and cash flows.
 
 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 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. 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 the 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.
 
 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 Arbitrator
          decided not to hear testimony on damages and closed the proceedings. On
          September 9, 2005, the Arbitrator issued an opinion to award approximately
          $16.1 million to the bargaining unit employees. JCP&L initiated an appeal of
          this award by filing a motion to vacate in Federal court in New Jersey
          on
          October 18, 2005. JCP&L recognized a liability for the potential $16.1
          million award during the three months ended September 30, 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 a tariff that would specifically
          allow the collection of transition charges from customers of municipal
          electric
          utilities formed after 1998. 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. It is unknown when the PUCO will rule on this
          case.
 
 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 13(C) to
          the consolidated financial statements for further details and a complete
          discussion of other legal proceedings.
 63
 
 **NEW
          ACCOUNTING STANDARDS AND INTERPRETATIONS**
 
 *FSP
          No. FAS
          13-1, "Accounting for Rental Costs Incurred during the Construction
          Period"*
  Issued
          in October
          2005, FSP No. FAS 13-1 requires rental costs associated with ground or
          building
          operating leases that are incurred during a construction period to
          be
          recognized as rental expense. The effective date of the FSP guidance is
          the
          first reporting period beginning after December 15, 2005. FirstEnergy is
          currently evaluating this FSP, and its impact on the financial
          statements.
 
 *EITF
          Issue
          04-13, "Accounting for Purchases and Sales of Inventory with the Same
          Counterparty"*
  In
          September 2005,
          the EITF reached a final consensus on Issue 04-13 concluding that two or
          more
          legally separate exchange transactions with the same counterparty should
          be
          combined and considered as a single arrangement for purposes of applying
          APB 29,
          when the transactions were entered into "in contemplation" of one another.
          If
          two transactions are combined and considered a single arrangement, the
          EITF
          reached a consensus that an exchange of inventory should be accounted for
          at
          fair value. Although electric power is not capable of being held in inventory,
          there is no substantive conceptual distinction between exchanges involving
          power
          and other storable inventory. Therefore, FirstEnergy will adopt this EITF
          effective for new arrangements entered into, or modifications or renewals
          of
          existing arrangements, in interim or annual periods beginning after March
          15,
          2006. See Note 2 for an example of FirstEnergy's application of this
          Issue.
 
 *EITF
                    Issue No. 05-6, "Determining the Amortization Period for Leasehold
                    Improvements Purchased after Lease Inception or Acquired in a
                    Business
                    Combination"*
  In
          June 2005, the
          EITF reached a consensus on the application guidance for Issue 05-6. EITF
          05-6
          addresses the amortization period for leasehold improvements that were
          either
          acquired in a business combination or placed in service significantly after
          and
          not contemplated at or near the beginning of the initial lease term. For
          leasehold improvements acquired in a business combination, the amortization
          period is the shorter of the useful life of the assets or a term that includes
          required lease periods and renewals that are deemed to be reasonably assured
          at
          the date of acquisition. Leasehold improvements that are placed in service
          significantly after and not contemplated at or near the beginning of the
          lease
          term should be amortized over the shorter of the useful life of the assets
          or a
          term that includes required lease periods and renewals that are deemed
          to be
          reasonably assured at the date the leasehold improvements are purchased.
          This
          EITF was effective July 1, 2005 and is consistent with FirstEnergy's current
          accounting.
 
 *FIN
          47,
“Accounting for Conditional Asset Retirement Obligations - an interpretation
          of
          FASB Statement No. 143”*
 
 On
          March 30,
          2005, the FASB issued FIN 47 to clarify the scope and timing of liability
          recognition for conditional asset retirement obligations. Under this
          interpretation, companies are required to recognize a liability for the
          fair
          value of an asset retirement obligation that is conditional on a future
          event,
          if the fair value of the liability can be reasonably estimated. In instances
          where there is insufficient information to estimate the liability, the
          obligation is to be recognized in the first period in which sufficient
          information becomes available to estimate its fair value. If the fair value
          cannot be reasonably estimated, that fact and the reasons why must be disclosed.
          This Interpretation is effective for FirstEnergy in the fourth quarter
          of 2005.
          FirstEnergy and the Companies are currently evaluating the effect this
          Interpretation will have on their financial statements.
 
 *SFAS
                    154
                    - “Accounting Changes and Error Corrections - a replacement of APB
                    Opinion
                    No. 20 and FASB Statement No.
                    3”*
 
 In
          May 2005, the
          FASB issued SFAS 154 to change the requirements for accounting and reporting
          a
          change in accounting principle. It applies to all voluntary changes in
          accounting principle and to changes required by an accounting pronouncement
          when
          that pronouncement does not include specific transition provisions. This
          Statement requires retrospective application to prior periods’ financial
          statements of changes in accounting principle, unless it is impracticable
          to
          determine either the period-specific effects or the cumulative effect of
          the
          change. In those instances, this Statement requires that the new accounting
          principle be applied to the balances of assets and liabilities as of the
          beginning of the earliest period for which retrospective application is
          practicable and that a corresponding adjustment be made to the opening
          balance
          of retained earnings (or other appropriate components of equity or net
          assets in
          the statement of financial position) for that period rather than being
          reported
          in the Consolidated Statements of Income. This Statement also requires
          that a
          change in depreciation, amortization, or depletion method for long-lived,
          nonfinancial assets be accounted for as a change in accounting estimate
          affected
          by a change in accounting principle. The provisions of this Statement are
          effective for accounting changes and corrections of errors made in fiscal
          years
          beginning after December 15, 2005. FirstEnergy and the Companies
          will adopt
          this Statement effective January 1, 2006.
  64
  *SFAS
                    153,
                    “Exchanges of Nonmonetary Assets - an amendment of APB Opinion
                    No.
                    29”*
  In
          December 2004,
          the FASB issued SFAS 153 amending APB 29, which was based on the principle
          that
          nonmonetary assets should be measured based on the fair value of the assets
          exchanged. The guidance in APB 29 included certain exceptions to that principle.
          SFAS 153 eliminates the exception from fair value measurement for nonmonetary
          exchanges of similar productive assets and replaces it with an exception
          for
          exchanges that do not have commercial substance. This Statement specifies
          that a
          nonmonetary exchange has commercial substance if the future cash flows
          of the
          entity are expected to change significantly as a result of the exchange.
          The
          provisions of this Statement are effective January 1, 2006 for FirstEnergy.
          This FSP is not expected to have a material impact on FirstEnergy's financial
          statements.
 
 *SFAS
          123(R),
“Share-Based Payment”*
 
 In
          December 2004,
          the FASB issued SFAS 123(R), a revision to SFAS 123, which requires expensing
          stock options in the financial statements. Important to applying the new
          standard is understanding how to (1) measure the fair value of stock-based
          compensation awards and (2) recognize the related compensation cost for
          those
          awards. For an award to qualify for equity classification, it must meet
          certain
          criteria in SFAS 123(R). An award that does not meet those criteria will
          be
          classified as a liability and remeasured each period. SFAS 123(R) retains
          SFAS
          123's requirements on accounting for income tax effects of stock-based
          compensation. In April 2005, the SEC delayed the effective date of SFAS
          123(R)
          to annual, rather than interim, periods that begin after June 15,
          2005. The
          SEC’s new rule results in a six-month deferral for companies with a fiscal
          year
          beginning January 1. Therefore, FirstEnergy will adopt this Statement
          effective January 1, 2006. FirstEnergy expects to adopt modified
          prospective application, without restatement of prior interim periods.
          Potential
          cumulative adjustments, if any, have not yet been determined. FirstEnergy
          uses
          the Black-Scholes option-pricing model to value options for disclosure
          purposes
          only and expects to apply this pricing model upon adoption of SFAS 123(R).
 
 *SFAS
          151,
“Inventory Costs - an amendment of ARB No. 43, Chapter 4”*
 
 In
          November 2004,
          the FASB issued SFAS 151 to clarify the accounting for abnormal amounts
          of idle
          facility expense, freight, handling costs and wasted material (spoilage).
          Previous guidance stated that in some circumstances these costs may be
“so
          abnormal” that they would require treatment as current period costs. SFAS 151
          requires abnormal amounts for these items to always be recorded as current
          period costs. In addition, this Statement requires that allocation of fixed
          production overheads to the cost of conversion be based on the normal capacity
          of the production facilities. The provisions of this statement are effective
          for
          inventory costs incurred by FirstEnergy beginning January 1, 2006.
          FirstEnergy is currently evaluating this Standard and does not expect it
          to have
          a material impact on the financial statements.
 
 *FSP
          FAS 115-1,
          "The Meaning of Other-Than-Temporary Impairment and its Application to
          Certain
          Investments"*
 
 In
          September 2005,
          the FASB finalized and renamed EITF 03-1 and 03-1-a to FSP FAS 115-1. FSP
          FAS
          115-1 will (1) supersede Issue 03-1 and EITF topic No. D-44, "Recognition
          of
          Other Than Temporary Impairment upon the Planned Sale of a Security Whose
          Cost
          Exceeds Fair Value," (2) clarify that an investor should recognize an impairment
          loss no later than when the impairment is deemed other than temporary,
          even if a
          decision to sell has not been made, and (3) be effective for
          other-than-temporary impairment and analyses conducted in periods beginning
          after September 15, 2005. The FASB expects to issue this FSP in
          the fourth
          quarter of 2005, which would require prospective application with an effective
          date for reporting periods beginning after December 15, 2005. FirstEnergy
          is
          currently evaluating this FSP and any impact on its investments.
 
 *FSP
          109-1,
“Application of FASB Statement No. 109, Accounting for Income Taxes, to
          the Tax
          Deduction and Qualified Production Activities Provided by the American
          Jobs
          Creation Act of 2004”*
  Issued
          in December
          2004, FSP 109-1 provides guidance related to the provision within the American
          Jobs Creation Act of 2004 (Act) that provides a tax deduction on qualified
          production activities. The Act includes a tax deduction of up to nine percent
          (when fully phased-in) of the lesser of (a) “qualified production activities
          income,” as defined in the Act, or (b) taxable income (after the deduction for
          the utilization of any net operating loss carryforwards). The FASB believes
          that
          the deduction should be accounted for as a special deduction in accordance
          with
          SFAS 109, “Accounting for Income Taxes", which is consistent with FirstEnergy's
          accounting.
 65






**OHIO
                    EDISON COMPANY****CONSOLIDATED
                    STATEMENTS OF INCOME AND COMPREHENSIVE INCOME****(Unaudited)****Three
                    Months Ended**
                
                **Nine
                    Months Ended****September
                    30,**
                
                **September
                    30,****2005**
                
                **2004**
                
                **2005**
                
                **2004*****(In
                    thousands)*****STATEMENTS
                    OF INCOME****OPERATING
                    REVENUES**
                
                $
                825,790
                
                $
                766,336
                
                $
                2,268,760
                
                $
                2,227,978**OPERATING
                    EXPENSES AND TAXES:**Fuel
                
                
                15,158
                
                
                15,244
                
                
                39,080
                
                
                44,158Purchased
                    power
                
                
                229,561
                
                
                242,835
                
                
                703,658
                
                
                730,542Nuclear
                    operating costs
                
                
                76,254
                
                
                81,244
                
                
                264,514
                
                
                235,277Other
                    operating costs
                
                
                114,762
                
                
                99,132
                
                
                293,530
                
                
                276,289Provision
                    for
                    depreciation
                
                
                30,169
                
                
                30,702
                
                
                87,875
                
                
                90,846Amortization
                    of regulatory assets
                
                
                126,439
                
                
                103,211
                
                
                347,880
                
                
                317,030Deferral
                    of
                    new regulatory assets
                
                
                (43,929
                )
                
                (25,728
                )
                
                (107,750
                )
                
                (69,790
                )General
                    taxes
                
                
                51,945
                
                
                47,634
                
                
                146,066
                
                
                135,688Income
                    taxes
                
                
                99,778
                
                
                76,502
                
                
                245,942
                
                
                203,863Total
                    operating expenses and taxes
                
                
                700,137
                
                
                670,776
                
                
                2,020,795
                
                
                1,963,903**OPERATING
                    INCOME**
                
                
                125,653
                
                
                95,560
                
                
                247,965
                
                
                264,075**OTHER
                    INCOME (net of income taxes)**
                
                
                20,069
                
                
                17,141
                
                
                37,352
                
                
                50,285**NET
                    INTEREST CHARGES:**Interest
                    on
                    long-term debt
                
                
                12,989
                
                
                10,657
                
                
                44,330
                
                
                43,641Allowance
                    for
                    borrowed funds used during constructionand
                    capitalized interest
                
                
                (3,014
                )
                
                (1,950
                )
                
                (8,255
                )
                
                (4,924
                )Other
                    interest expense
                
                
                4,193
                
                
                640
                
                
                12,457
                
                
                7,576Subsidiary's
                    preferred stock dividend requirements
                
                
                156
                
                
                639
                
                
                1,534
                
                
                1,919Net
                    interest
                    charges
                
                
                14,324
                
                
                9,986
                
                
                50,066
                
                
                48,212**NET
                    INCOME**
                
                
                131,398
                
                
                102,715
                
                
                235,251
                
                
                266,148**PREFERRED
                    STOCK DIVIDEND REQUIREMENTS**
                
                
                659
                
                
                623
                
                
                1,976
                
                
                1,843**EARNINGS
                    ON COMMON STOCK**
                
                $
                130,739
                
                $
                102,092
                
                $
                233,275
                
                $
                264,305**STATEMENTS
                    OF COMPREHENSIVE INCOME****NET
                    INCOME**
                
                $
                131,398
                
                $
                102,715
                
                $
                235,251
                
                $
                266,148**OTHER
                    COMPREHENSIVE INCOME (LOSS):**Unrealized
                    loss on available for sale securities
                
                
                (3,402
                )
                
                (6,913
                )
                
                (19,079
                )
                
                (2,767
                )Income
                    tax
                    benefit related to other comprehensive income
                
                
                2,043
                
                
                2,850
                
                
                7,713
                
                
                1,141Other
                    comprehensive loss, net of tax
                
                
                (1,359
                )
                
                (4,063
                )
                
                (11,366
                )
                
                (1,626
                )**TOTAL
                    COMPREHENSIVE INCOME**
                
                $
                130,039
                
                $
                98,652
                
                $
                223,885
                
                $
                264,522The
                    preceding
                    Notes to Consolidated Financial Statements as they relate to
                    Ohio Edison
                    Company are an integral part of thesestatements.
    66
   **OHIO
                    EDISON COMPANY****CONSOLIDATED
                    BALANCE SHEETS****(Unaudited)****September
                    30,**
                
                **December
                    31,****2005**
                
                **2004*****(In
                    thousands)*****ASSETS****UTILITY
                    PLANT:**In
                    service
                
                $
                5,573,996
                
                $
                5,440,374Less
                    -
                    Accumulated provision for depreciation
                
                
                2,793,343
                
                
                2,716,8512,780,653
                
                
                2,723,523Construction
                    work in progress -Electric
                    plant
                
                
                246,325
                
                
                203,167Nuclear
                    fuel
                
                
                17,972
                
                
                21,694264,297
                
                
                224,8613,044,950
                
                
                2,948,384**OTHER
                    PROPERTY AND INVESTMENTS:**Investment
                    in
                    lease obligation bonds
                
                
                341,335
                
                
                354,707Nuclear
                    plant
                    decommissioning trusts
                
                
                462,439
                
                
                436,134Long-term
                    notes receivable from associated companies
                
                
                207,089
                
                
                208,170Other
                
                
                44,623
                
                
                48,5791,055,486
                
                
                1,047,590**CURRENT
                    ASSETS:**Cash
                    and cash
                    equivalents
                
                
                900
                
                
                1,230Receivables
                    -Customers
                    (less accumulated provisions of $7,312,000 and $6,302,000,
                    respectively,for
                    uncollectible accounts)
                
                
                285,462
                
                
                274,304Associated
                    companies
                
                
                121,262
                
                
                245,148Other
                    (less
                    accumulated provisions of $14,000 and $64,000,
                    respectively,for
                    uncollectible accounts)
                
                
                20,653
                
                
                18,385Notes
                    receivable from associated companies
                
                
                798,513
                
                
                538,871Materials
                    and
                    supplies, at average cost
                
                
                92,610
                
                
                90,072Prepayments
                    and other
                
                
                17,336
                
                
                13,1041,336,736
                
                
                1,181,114**DEFERRED
                    CHARGES:**Regulatory
                    assets
                
                
                844,590
                
                
                1,115,627Property
                    taxes
                
                
                61,419
                
                
                61,419Unamortized
                    sale and leaseback costs
                
                
                56,477
                
                
                60,242Other
                
                
                67,093
                
                
                68,2751,029,579
                
                
                1,305,563$
                6,466,751
                
                $
                6,482,651**CAPITALIZATION
                    AND LIABILITIES****CAPITALIZATION:**Common
                    stockholder's equity -Common
                    stock,
                    without par value, authorized 175,000,000 shares - 100 shares
                    outstanding
                
                $
                2,099,099
                
                $
                2,098,729Accumulated
                    other comprehensive loss
                
                
                (58,484
                )
                
                (47,118
                )Retained
                    earnings
                
                
                434,473
                
                
                442,198Total
                    common
                    stockholder's equity
                
                
                2,475,088
                
                
                2,493,809Preferred
                    stock
                
                
                60,965
                
                
                60,965Preferred
                    stock of consolidated subsidiary
                
                
                14,105
                
                
                39,105Long-term
                    debt
                    and other long-term obligations
                
                
                1,099,147
                
                
                1,114,9143,649,305
                
                
                3,708,793**CURRENT
                    LIABILITIES:**Currently
                    payable long-term debt
                
                
                273,656
                
                
                398,263Short-term
                    borrowings -Associated
                    companies
                
                
                120,971
                
                
                11,852Other
                
                
                123,584
                
                
                167,007Accounts
                    payable -Associated
                    companies
                
                
                81,980
                
                
                187,921Other
                
                
                11,289
                
                
                10,582Accrued
                    taxes
                
                
                213,843
                
                
                153,400Other
                
                
                117,268
                
                
                74,663942,591
                
                
                1,003,688**NONCURRENT
                    LIABILITIES:**Accumulated
                    deferred income taxes
                
                
                688,702
                
                
                766,276Accumulated
                    deferred investment tax credits
                
                
                52,108
                
                
                62,471Asset
                    retirement obligation
                
                
                364,525
                
                
                339,134Retirement
                    benefits
                
                
                320,044
                
                
                307,880Other
                
                
                449,476
                
                
                294,4091,874,855
                
                
                1,770,170**COMMITMENTS
                    AND CONTINGENCIES (Note 13)**$
                6,466,751
                
                $
                6,482,651The
                    preceding
                    Notes to Consolidated Financial Statements as they relate to
                    Ohio Edison
                    Company are an integral part of these balance sheets.
    67
    **OHIO
                    EDISON COMPANY****CONSOLIDATED
                    STATEMENTS OF CASH FLOWS****(Unaudited)****Three
                    Months Ended**
                
                **Nine
                    Months Ended****September
                    30,**
                
                **September
                    30,****2005**
                
                **2004**
                
                **2005**
                
                **2004*****(In
                    thousands)*****CASH
                    FLOWS FROM OPERATING ACTIVITIES:**Net
                    income
                
                $
                131,398
                
                $
                102,715
                
                $
                235,251
                
                $
                266,148Adjustments
                    to reconcile net income to net cash fromoperating
                    activities -Provision
                    for
                    depreciation
                
                
                30,169
                
                
                30,702
                
                
                87,875
                
                
                90,846Amortization
                    of regulatory assets
                
                
                126,439
                
                
                103,211
                
                
                347,880
                
                
                317,030Deferral
                    of
                    new regulatory assets
                
                
                (43,929
                )
                
                (25,728
                )
                
                (107,750
                )
                
                (69,790
                )Nuclear
                    fuel
                    and lease amortization
                
                
                11,867
                
                
                11,914
                
                
                30,530
                
                
                33,766Amortization
                    of lease costs
                
                
                32,963
                
                
                33,037
                
                
                30,011
                
                
                30,585Amortization
                    of electric service obligation
                
                
                (4,565
                )
                
                -
                
                
                (8,556
                )
                
                -Deferred
                    income taxes and investment tax credits, net
                
                
                (17,787
                )
                
                (11,374
                )
                
                (22,929
                )
                
                (61,961
                )Accrued
                    retirement benefit obligations
                
                
                5,503
                
                
                7,253
                
                
                12,164
                
                
                24,482Accrued
                    compensation, net
                
                
                1,254
                
                
                1,106
                
                
                (1,903
                )
                
                5,138Pension
                    trust
                    contribution
                
                
                -
                
                
                (72,763
                )
                
                -
                
                
                (72,763
                )Decrease
                    (increase) in operating assets -Receivables
                
                
                32,715
                
                
                (86,506
                )
                
                110,460
                
                
                (10,734
                )Materials
                    and
                    supplies
                
                
                15,611
                
                
                (2,930
                )
                
                (2,538
                )
                
                (8,796
                )Prepayments
                    and other current assets
                
                
                2,988
                
                
                4,878
                
                
                (4,232
                )
                
                (1,636
                )Increase
                    (decrease) in operating liabilities -Accounts
                    payable
                
                
                (20,007
                )
                
                115,690
                
                
                (105,234
                )
                
                21,905Accrued
                    taxes
                
                
                41,365
                
                
                (4,464
                )
                
                60,443
                
                
                (346,918
                )Accrued
                    interest
                
                
                2,458
                
                
                3,028
                
                
                1,667
                
                
                2,918Prepayment
                    for electric service - education programs
                
                
                -
                
                
                -
                
                
                136,142
                
                
                -Other
                
                
                (11,504
                )
                
                2,572
                
                
                1,372
                
                
                (8,624
                )Net
                    cash
                    provided from operating activities
                
                
                336,938
                
                
                212,341
                
                
                800,653
                
                
                211,596**CASH
                    FLOWS FROM FINANCING ACTIVITIES:**New
                    Financing
                    -Long-term
                    debt
                
                
                -
                
                
                -
                
                
                146,450
                
                
                30,000Short-term
                    borrowings, net
                
                
                18,254
                
                
                91,072
                
                
                65,696
                
                
                13,258Redemptions
                    and Repayments -Preferred
                    stock
                
                
                -
                
                
                -
                
                
                (37,750
                )
                
                -Long-term
                    debt
                
                
                (17,819
                )
                
                (36,090
                )
                
                (278,327
                )
                
                (152,900
                )Dividend
                    Payments -Common
                    stock
                
                
                (64,000
                )
                
                (68,000
                )
                
                (241,000
                )
                
                (239,000
                )Preferred
                    stock
                
                
                (659
                )
                
                (623
                )
                
                (1,976
                )
                
                (1,843
                )Net
                    cash used
                    for financing activities
                
                
                (64,224
                )
                
                (13,641
                )
                
                (346,907
                )
                
                (350,485
                )**CASH
                    FLOWS FROM INVESTING ACTIVITIES:**Property
                    additions
                
                
                (69,346
                )
                
                (61,682
                )
                
                (190,804
                )
                
                (146,645
                )Contributions
                    to nuclear decommissioning trusts
                
                
                (7,885
                )
                
                (7,885
                )
                
                (23,655
                )
                
                (23,655
                )Loan
                    repayments from (loans to) associated companies, net
                
                
                (200,021
                )
                
                (378,081
                )
                
                (258,561
                )
                
                30,709Proceeds
                    from
                    certificates of deposit
                
                
                -
                
                
                277,763
                
                
                -
                
                
                277,763Other
                
                
                4,155
                
                
                (29,200
                )
                
                18,944
                
                
                113Net
                    cash
                    provided from (used for) investing activities
                
                
                (273,097
                )
                
                (199,085
                )
                
                (454,076
                )
                
                138,285Net
                    decrease
                    in cash and cash equivalents
                
                
                (383
                )
                
                (385
                )
                
                (330
                )
                
                (604
                )Cash
                    and cash
                    equivalents at beginning of period
                
                
                1,283
                
                
                1,664
                
                
                1,230
                
                
                1,883Cash
                    and cash
                    equivalents at end of period
                
                $
                900
                
                $
                1,279
                
                $
                900
                
                $
                1,279The
                    preceding
                    Notes to Consolidated Financial Statements as they relate to
                    Ohio Edison
                    Company are an integral part of thesestatements.
    68







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





























To
      the Stockholders
      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, 2005, and the related consolidated
      statements of income and comprehensive income and cash flows for each of the
      three-month and nine-month periods ended September 30, 2005 and 2004.
      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
      previously
      audited, in accordance with the standards of the Public Company Accounting
      Oversight Board (United States), the consolidated balance sheet as of
      December 31, 2004, and the related consolidated statements of income,
      capitalization, common stockholder’s 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,
      2004 and the effectiveness of the Company’s internal control over financial
      reporting as of December 31, 2004; 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)
      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 March 7, 2005, 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 information as of December 31,
      2004, is fairly stated in all material respects in relation to the consolidated
      balance sheet from which it has been derived.














PricewaterhouseCoopers
      LLP


Cleveland,
      Ohio


November
      1,
      2005





69




**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. The OE Companies also
        provide generation services to those customers electing to retain the OE
        Companies as their power supplier. The OE Companies provide power directly
        to
        wholesale customers under previously negotiated contracts, as well as to
        some
        alternative energy suppliers under OE’s transition plan. The OE Companies have
        unbundled the price of electricity into its component elements - including
        generation, transmission, distribution and transition charges. Power supply
        requirements of the OE Companies are provided by FES -- an affiliated
        company.
 
 **Results
        of Operations**
  Earnings
        on common
        stock in the third quarter of 2005 increased to $131 million from $102 million
        in the third quarter of 2004. The increase in earnings resulted primarily
        from
        higher operating revenues and lower purchased power and nuclear operating
        costs,
        partially offset by increases in regulatory asset amortization, other operating
        costs and income taxes. During the first nine months of 2005, earnings on
        common
        stock decreased to $233 million from $264 million in the same period of 2004.
        The decrease in earnings for the first nine months of 2005 primarily resulted
        from increases in nuclear operating costs, regulatory asset amortization
        and a
        one-time income tax charge that occurred in the second quarter of 2005, as
        well
        as a decrease in other income. These reductions to earnings were partially
        offset by higher operating revenues and lower fuel and purchased power costs.
 
 Operating
        revenues
        increased by $59 million or 7.8% in the third quarter of 2005 compared with
        the
        same period in 2004. Higher revenues for the quarter primarily resulted from
        increased retail generation and distribution revenues of $23 million and
        $33
        million, respectively. During the first nine months of 2005 compared to the
        same
        period in 2004, operating revenues increased by $41 million or 1.8%. Higher
        revenues for the first nine months of 2005 were due to increases in retail
        generation and distribution revenues of $36 million and $40 million,
        respectively, partially offset by a $37 million decrease in wholesale sales.
 
 Lower
        wholesale
        revenues for the first nine months of 2005 reflected decreased sales to FES
        of
        $57 million (12.1% KWH sales decrease), due to reduced nuclear generation
        available for sale. The decreased sales to FES were partially offset by
        increased sales of $21 million to non-affiliated customers (including MSG
        sales). Under its Ohio transition plan, OE is required to provide MSG to
        non-affiliated alternative suppliers (see Outlook - Regulatory Matters).
 
 Increased
        retail
        generation revenues for the third quarter of 2005 resulted from higher sales
        to
        residential, commercial and industrial customers of $10 million, $2 million
        and
        $11 million, respectively. The increased generation KWH sales to residential
        (14.0%) and commercial (6.1%) customers were due to warmer than normal
        temperatures in the third quarter of 2005. Increased industrial revenues
        reflected a 6.5% increase in generation KWH sales. Partially offsetting the
        increase in residential KWH sales was an increase in customer shopping.
        Generation services provided to residential customers by alternative suppliers
        as a percent of total residential sales delivered in OE’s service area increased
        by 1.2 percentage points compared with the third quarter of 2004. Commercial
        and
        industrial customer shopping remained relatively unchanged.
 
 Retail
        generation
        revenues increased for the first nine months of 2005 compared to the same
        period
        of 2004 in all customer sectors (residential - $15 million, commercial -
        $7
        million and industrial - $14 million). The higher revenues were due to increased
        generation KWH sales (residential - 6.8%, commercial - 4.2% and industrial
        -
        1.0%). Residential and industrial KWH sales increases were partially offset
        by
        increases in customer shopping by 1.1 and 1.7 percentage points, respectively,
        while commercial shopping remained relatively unchanged.
 
 Revenues
        from
        distribution throughput increased $33 million in the third quarter of 2005
        compared with the same period in 2004. Distribution deliveries to residential,
        commercial and industrial customers increased by $26 million, $4 million
        and $3 million, respectively, due to increased KWH deliveries. The increases
        from distribution deliveries were partially offset by lower composite unit
        prices in all sectors.
 
 Revenues
        from
        distribution throughput increased $40 million in the first nine months of
        2005
        compared with the same period in 2004 due to higher revenues from residential
        and commercial customers, partially offset by lower industrial sector revenues.
        Residential and commercial distribution revenues increased $40 million and
        $3 million, respectively, reflecting higher KWH deliveries partially
        offset
        by lower composite prices. Industrial distribution revenues decreased by
        $3
        million due to lower composite unit prices, partially offset by an increase
        in
        KWH distribution deliveries.


70


Under
        the Ohio
        transition plan, OE provides incentives to customers to encourage switching
        to
        alternative energy providers. OE’s revenues were reduced by $3 million from
        additional credits in the third quarter and $7 million in the first nine
        months
        of 2005 compared to the same periods in 2004. These revenue reductions are
        deferred for future recovery from customers under OE’s transition plan and do
        not affect current period earnings (See Regulatory Matters below).
 
 Changes
        in KWH
        sales by customer class in the three months and nine months ended
        September 30, 2005 from the corresponding periods of 2004 are summarized
        in
        the following table:


**Three**
            
            **Nine****Changes
                in KWH Sales**
            
            **Months**
            
            **Months****Increase
                (Decrease)**Electric
                Generation:Retail
            
            
            9.1
            %
            
            3.9
            %Wholesale
            
            
            (1.2
            )%
            
            (9.4
            )%**Total
                Electric Generation Sales**
            
            
            **4.0**
            **%**
            
            **(2.6**
            **)%**Distribution
                Deliveries:Residential
            
            
            15.9
            %
            
            8.3
            %Commercial
            
            
            6.3
            %
            
            4.2
            %Industrial
            
            
            6.9
            %
            
            3.4
            %**Total
                Distribution Deliveries**
            
            
            **9.8**
            **%**
            
            **5.3**
            **%**





*Operating
        Expenses and Taxes*
  Total
        operating
        expenses and taxes increased by $29 million in the third quarter and $57
        million
        in the first nine months of 2005 from the same periods of 2004. The following
        table presents changes from the prior year by expense
        category.


**Operating
                            Expenses and Taxes - Changes**
                        
                        **Three
                            Months**
                        
                        **Nine
                            Months****Increase
                            (Decrease)**
                        
                        ***(In
                            millions)***Fuel
                            costs
                        
                        $
                        --
                        
                        $
                        (5
                        )Purchased
                            power costs
                        
                        
                        (13
                        )
                        
                        (27
                        )Nuclear
                            operating costs
                        
                        
                        (5
                        )
                        
                        29Other
                            operating costs
                        
                        
                        16
                        
                        
                        17Provision
                            for
                            depreciation
                        
                        
                        (1
                        )
                        
                        (3
                        )Amortization
                            of regulatory assets
                        
                        
                        23
                        
                        
                        31Deferral
                            of
                            new regulatory assets
                        
                        
                        (18
                        )
                        
                        (38
                        )General
                            taxes
                        
                        
                        4
                        
                        
                        11Income
                            taxes
                        
                        
                        23
                        
                        
                        42**Net
                            increase in operating expenses and taxes**
                        
                        $
                        29
                        
                        $
                        57





Lower
        fuel costs in
        the first nine months of 2005, compared with the same periods of 2004, resulted
        from decreased nuclear generation - down 12.1%. Purchased power costs were
        lower
        in both periods of 2005, reflecting lower unit costs partially offset by
        higher
        KWH purchases in the third quarter of 2005. KWH purchases were relatively
        unchanged in the first nine months of 2005. Nuclear operating costs decreased
        in
        the third quarter of 2005 compared to the same quarter in 2004 primarily
        due to
        a decrease in non-fuel nuclear operating costs at Perry Unit 1 and Beaver
        Valley
        Unit 2. Nuclear operating costs increased during the first nine months of
        2005
        primarily due to the costs from the Beaver Valley Unit 2 refueling outage
        (started April 4, 2005) and to a lesser extent from the Perry Unit 1 outage
        initiated in the first quarter of 2005 that was completed on May 6, 2005.
        There
        were no nuclear refueling outages in the same periods last year. The increases
        in other operating costs in the third quarter and first nine months of 2005,
        compared to the same periods of 2004, resulted primarily from increased MISO
        transmission expenses, partially offset by lower employee benefits
        expenses.
 
 The
        decrease in
        depreciation expense in the first nine months of 2005 compared with the same
        period of 2004 was attributable to revised estimated service life assumptions
        for fossil generating plants (see Note 3). Higher regulatory asset amortization
        in the three-month and nine-month periods was primarily due to increased
        amortization of transition costs being recovered under the RSP. Increases
        in
        regulatory asset deferrals for both periods resulted from higher shopping
        incentive deferrals and related interest ($4 million and $11 million,
        respectively), and the PUCO-approved MISO administrative cost deferrals and
        related interest ($14 million and $27 million, respectively, see Outlook
        -
        Regulatory Matters).




71




General
        taxes
        increased in the third quarter and first nine months of 2005 compared to
        the
        same periods of 2004 due to the effect of higher KWH sales which increased
        Ohio
        KWH excise taxes in both periods. The increase in the first nine months of
        2005
        also reflected the absence of a $6 million Pennsylvania property tax refund
        recognized in the second quarter of 2004.
 
 Income
        taxes
        increased in the first nine months of 2005 compared to the same periods of
        2004,
        primarily due to the effects of new tax legislation in Ohio. On June 30,
        2005,
        the State of Ohio enacted new tax legislation that created a new CAT tax,
        which
        is based on qualifying “taxable gross receipts” and will not consider any
        expenses or costs incurred to generate such receipts, except for items such
        as
        cash discounts, returns and allowances, and bad debts. The CAT tax was effective
        July 1, 2005, and replaces the Ohio income-based franchise tax and
        the Ohio
        personal property tax. The CAT tax is phased-in while the current income-based
        franchise tax is phased-out over a five-year period at a rate of 20% annually,
        beginning with the year ended 2005, and personal property tax is phased-out
        over
        a four-year period at a rate of approximately 25% annually, beginning with
        the
        year ended 2005. During the phase-out period the Ohio income tax will be
        computed consistently with the prior tax law, except that the tax liability
        as
        computed will be multiplied by 4/5 in 2005; 3/5 in 2006; 2/5 in 2007 and
        1/5 in
        2008, therefore eliminating the current income-based franchise tax over a
        five-year period.
 
 As
        a result of the
        new tax structure, all net deferred tax benefits that are not expected to
        reverse during the five-year phase-in period were written-off as of
        June 30, 2005. The
        impact on
        income taxes associated with the required adjustment to net deferred taxes
        for
        the nine months ended September 30, 2005 was an additional tax expense
        of
        approximately $36 million, which was partially offset by the initial phase-out
        of the Ohio income-based franchise tax, which reduced income taxes by
        approximately $7 million in the nine months ended September 30, 2005.
        See
        Note 12 to the consolidated financial statements.
 
 *Other
        Income*
 
 Other
        income
        decreased $13 million in the first nine months of 2005 compared with the
        same
        period of 2004, primarily due to an $8.5 million civil penalty payable to
        the
        Department of Justice and a $10 million liability for environmental projects
        recognized in connection with the W.H. Sammis Plant settlement (see Outlook
        -
        Environmental Matters), partially offset by higher nuclear decommissioning
        trust
        realized gains.
 
 *Net
        Interest
        Charges*
 
 Net
        interest
        charges increased by $4 million in the third quarter and $2 million in the
        first
        nine months of 2005 compared with the same periods of 2004, reflecting increased
        short-term borrowings from associated companies at a higher rate of
        interest.
 
 **Capital
        Resources and Liquidity**
 
 OE’s
        cash
        requirements for the remainder of 2005 for operating expenses, construction
        expenditures, scheduled debt maturities and preferred stock redemptions are
        expected to be met without increasing OE’s net debt and preferred stock
        outstanding. Borrowing capacity under credit facilities is available to manage
        working capital requirements. Thereafter, OE expects to use a combination
        of
        cash from operations and funds from the capital markets.
 
 *Changes
        in Cash
        Position*
 
 As
        of September 30,
        2005, OE's cash and cash equivalents of approximately $1 million remained
        unchanged from December 31, 2004.


72




*Cash
        Flows From
        Operating Activities*
 
 Cash
        provided from
        operating activities during the third quarter and first nine months of 2005,
        compared with the corresponding periods in 2004 were as follows:


**Three
                Months Ended**
            
            **Nine
                Months Ended****September
                30,**
            
            **September
                30,****Operating
                Cash Flows**
            
            **2005**
            
            **2004**
            
            **2005**
            
            **2004*****(In
                millions)***Cash
                earnings(1)
            
            $
            273
            
            $
            224
            
            $
            603
            
            $
            607Pension
                trust
                contribution(2)
            
            
            --
            
            
            (44
            )
            
            --
            
            
            (44
            )Working
                capital and other
            
            
            64
            
            
            32
            
            
            198
            
            
            (351
            )Total
                cash
                flows from operating activities
            
            $
            337
            
            $
            212
            
            $
            801
            
            $
            212(1)Cash
                earnings is a non-GAAP measure (see reconciliation
                below).(2)Pension
                trust contribution net of $29 million of income tax
                benefits.





Cash
        earnings, as
        disclosed 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. The following table reconciles
        cash earnings with net income.


**Three
                Months Ended**
            
            **Nine
                Months Ended****September
                30,**
            
            **September
                30,****Reconciliation
                of Cash Earnings**
            
            **2005**
            
            **2004**
            
            **2005**
            
            **2004*****(In
                millions)***Net
                income
                (GAAP)
            
            $
            131
            
            $
            103
            
            $
            235
            
            $
            266Non-cash
                charges (credits):Provision
                for
                depreciation
            
            
            30
            
            
            31
            
            
            88
            
            
            91Amortization
                of regulatory assets
            
            
            126
            
            
            103
            
            
            348
            
            
            317Amortization
                of lease costs
            
            
            33
            
            
            33
            
            
            30
            
            
            31Nuclear
                fuel
                and capital lease amortization
            
            
            12
            
            
            12
            
            
            31
            
            
            34Deferral
                of
                new regulatory assets
            
            
            (44
            )
            
            (26
            )
            
            (108
            )
            
            (70
            )Deferred
                income taxes and investment tax credits, net
            
            
            (18
            )
            
            (40
            )
            
            (23
            )
            
            (91
            )Other
                non-cash items
            
            
            3
            
            
            8
            
            
            2
            
            
            29Cash
                earnings
                (Non-GAAP)
            
            $
            273
            
            $
            224
            
            $
            603
            
            $
            607






Net
        cash provided
        from operating activities increased $125 million in the third quarter of
        2005,
        compared with the third quarter of 2004, due to a $32 million increase from
        changes in working capital, the absence of a $44 million after-tax
        voluntary pension trust contribution made in the third quarter of 2004 and
        a $49
        million increase in cash earnings as described above and under “Results from
        Operations”. The increase in working capital primarily reflects changes in
        accrued taxes of $46 million (including a $249 million reallocation of tax
        liabilities among the FirstEnergy subsidiaries pursuant to the tax sharing
        agreement), partially offset by changes in accounts payable and accounts
        receivable of $16 million.
 
 Net
        cash provided
        from operating activities increased $589 million in the first nine months
        of
        2005, compared with the same period in 2004, due to a $549 million increase
        from
        changes in working capital, the absence of a $44 million after-tax
        voluntary pension trust contribution made in the third quarter of 2004,
        partially offset by a $4 million decrease in cash earnings as described
        above and under “Results from Operations”. The increase in working capital
        primarily reflects changes in accrued taxes of $407 million (including a
        $249
        million reallocation of tax liabilities among the FirstEnergy subsidiaries
        pursuant to the tax sharing agreement) and $136 million of funds received
        for
        the Energy for Education program in the second quarter of 2005.
 
 *Cash
        Flows From
        Financing Activities*
  Net
        cash used for
        financing activities increased to $64 million in the third quarter of 2005
        from
        $14 million in the third quarter of 2004. The increase primarily resulted
        from a
        $72 million decrease in new short-term borrowings, partially offset by an
        $18
        million decrease in redemptions and repayments. Net cash used for financing
        activities decreased to $347 million in the first nine months of 2005 from
        $350
        million in the same period of 2004. The decrease was due to a $169 million
        increase in new debt and short term borrowings partially offset by a $163
        million increase in net debt and preferred stock redemptions.


73




On
        May 16,
        2005, Penn redeemed all 127,500 outstanding shares of 7.625% preferred stock
        at
        $102.29 per share and all 250,000 outstanding shares of 7.75% preferred stock
        at
        $100 per share, including accrued dividends to the date of redemption.
 
 OE
        had
        approximately $799 million of cash and temporary cash investments (which
        include
        short-term notes receivable from associated companies) and $245 million of
        short-term indebtedness as of September 30, 2005. OE has authorization
        from
        the PUCO to incur short-term debt of up to $500 million (including bank
        facilities and the utility money pool described below). Penn has authorization
        from the SEC to incur short-term debt up to its charter limit of
        $51 million (including 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, 2005, the facility was drawn for
        $120 million.
 
 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. 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, 2005, the facility was not drawn. On July 15,
        2005, the
        facility was renewed until June 29, 2006. The annual facility fee
        is 0.25%
        on the entire finance limit.
 
 As
        of October 24,
        2005, OE and Penn had the aggregate capability to issue approximately $1.1
        billion of additional FMB on the basis of property additions and retired
        bonds
        under the terms of their respective mortgage indentures following the recently
        completed intra-system transfer of fossil generating plants (see Note 17).
        The
        issuance of FMB by OE is also subject to provisions of its 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 to
        incur
        additional secured debt not otherwise permitted by a specified exception
        of up
        to $690 million as of October 24, 2005. Based upon applicable earnings coverage
        tests in their respective charters, OE and Penn could issue a total of $2.8
        billion of preferred stock (assuming no additional debt was issued) as of
        September 30, 2005. It is estimated that the annualized impact of
        the
        intra-system transfer of fossil generating plants will reduce the aggregate
        capability of OE and Penn to issue preferred stock by approximately 17%.
 
 On
        June 14,
        2005, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI,
        as Borrowers, entered into a syndicated $2 billion five-year revolving credit
        facility. Borrowings under the facility are available to each Borrower
        separately and mature on the earlier of 364 days from the date of borrowing
        or
        the commitment termination date, as the same may be extended. OE's and Penn’s
        borrowing limits under the facility are $550 million.
 
 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 third quarter of 2005
        was
        3.50%.
 
 OE’s
        access to
        capital markets and costs of financing are dependent on the ratings of its
        securities and the securities of FirstEnergy.
 
 On
        July 18,
        2005, Moody’s revised its rating outlook on FirstEnergy and its subsidiaries to
        positive from stable. Moody’s stated that the revision to FirstEnergy’s outlook
        resulted from steady financial improvement and steps taken by management
        to
        improve operations, including the stabilization of its nuclear operations.
        Moody’s further stated that the revision in their outlook recognized
        management’s regional strategy of focusing on its core utility businesses and
        the improvement in FirstEnergy’s credit profile stemming from the application of
        free cash flow toward debt reduction. Moody’s noted that a ratings upgrade could
        be considered if FirstEnergy continues to achieve planned improvements in
        its
        operations and balance sheet.
 
 On
        October 3,
        2005, S&P raised its corporate credit rating on FirstEnergy and the EUOC to
        'BBB' from 'BBB-'. At the same time, S&P raised the senior unsecured ratings
        at the holding company to 'BBB-' from 'BB+' and each of the EUOC by one notch
        above the previous rating. S&P noted that the upgrade followed the
        continuation of a good operating track record, specifically for the nuclear
        fleet through the third quarter 2005. S&P also stated that FirstEnergy’s
        rating reflects the benefits of supportive regulation, low-cost base load
        generation fleet, low-risk transmission and distribution operations and rate
        certainty in Ohio. FirstEnergy’s ability to consistently generate free cash
        flow, good liquidity, and an improving financial profile were also noted
        as
        strengths.




74


*Cash
          Flows From
          Investing Activities*
  Net
          cash used for
          investing activities increased by $74 million in the third quarter of 2005
          and
          $592 million in the first nine months of 2005, from the same periods
          of
          2004. These increases resulted primarily from $278 million in cash
          proceeds
          from certificates of deposit during the third quarter 2004. Loans to associated
          companies decreased $178 million in the third quarter of 2005, partially
          offsetting the proceeds from certificates of deposit, and increased
          $289 million in the first nine months of 2005.
 
 In
          the last quarter
          of 2005, capital requirements for property additions and capital leases
          are
          expected to be approximately $82 million. OE has additional requirements
          of
          approximately $8 million to meet sinking fund requirements for preferred
          stock
          and maturing long-term debt (excluding Penn’s optional redemptions disclosed
          above) during the remainder of 2005. These cash requirements are expected
          to be
          satisfied from internal cash and short-term credit arrangements. OE’s capital
          spending for the period 2005-2007 is expected to be about $667 million
          of which
          approximately $233 million applies to 2005.
 
 **FirstEnergy
          Intra-System Generation Asset Transfers**
 
 On
          May 13,
          2005, Penn, and on May 18, 2005, OE, CEI and TE, entered into certain
          agreements implementing a series of intra-system generation asset transfers.
          When fully completed, the asset transfers will result in the respective
          undivided ownership interests of the Ohio Companies and Penn in FirstEnergy’s
          nuclear and non-nuclear plants being owned by NGC, and FGCO, respectively.
          The
          generating plant interests that are being transferred do 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 transfer of non-nuclear generation
          assets
          to FGCO. The OE Companies currently expect to complete the transfer of
          nuclear
          generation assets to NGC through a spin-off by way of dividend before the
          end of
          2005. Consummation of the nuclear transfer remains subject to necessary
          regulatory approvals.
 
 These
          transactions
          are being undertaken in connection with 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. FENOC currently operates and maintains the nuclear generation
          assets to be transferred. FGCO, as lessee under a Master Facility Lease,
          leased,
          operated and maintained the non-nuclear generation assets that it now owns.
          The
          transactions will essentially complete the divestitures contemplated by
          the
          restructuring plans by transferring the ownership interests to NGC and
          FGCO,
          respectively, without impacting the operation of the plants.
 
 See
          Note 17 to the
          consolidated financial statements for OE's and Penn’s disclosure of the assets
          held for sale as of September 30, 2005.
 
 **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 $678 million as of September 30, 2005.
 
 **Equity
          Price Risk**
  Included
          in OE’s
          nuclear decommissioning trust investments are marketable equity securities
          carried at their market value of approximately $262 million and $248 million
          as
          of September 30, 2005 and December 31, 2004, respectively. A hypothetical
          10% decrease in prices quoted by stock exchanges would result in a $26
          million
          reduction in fair value as of September 30, 2005. 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.
 
 75




**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***
 
 In
        2001, Ohio
        customer rates were restructured to establish separate charges for transmission,
        distribution, transition cost recovery and a generation-related component.
        When
        one of OE's customers elects to obtain power from an alternative supplier,
        OE
        reduces the customer's bill with a "generation shopping credit," based on
        the
        generation component (plus an incentive), and the customer receives a generation
        charge from the alternative supplier. OE has continuing PLR responsibility
        to
        its franchise customers through December 31, 2008 unless the PUCO
        accepts
        future competitive bid results prior to the end of that period under the
        revised
        RSP.
 
 As
        part of OE's
        transition plan, it is obligated to supply electricity to customers who do
        not
        choose an alternative supplier. OE is also required to provide 560 MW of
        low
        cost supply (MSG) to unaffiliated alternative suppliers who serve customers
        within its service area. FES acts as an alternate supplier for a portion
        of the
        load in OE's franchise area.
 
 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 competitive
        bid
        process. The RSP was filed by the Ohio Companies to establish generation
        service
        rates beginning January 1, 2006, in response to PUCO 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 this proceeding as well as the associated entries on rehearing. On
        September 28, 2005, the Ohio Supreme Court heard oral argument on
        the
        appeals.
 
 On
        May 27,
        2005, OE filed an application with the PUCO to establish a GCAF rider under
        the
        RSP. The application seeks to implement recovery of increased fuel costs
        from
        2006 through 2008 applicable to OE’s retail customers through a tariff rider to
        be implemented January 1, 2006. The application reflects projected
        increases in fuel costs in 2006 compared to 2002 baseline costs. The new
        rider,
        after adjustments made in testimony, is seeking to recover all costs above
        the
        baseline (approximately $88 million in 2006 for all of the Ohio Companies).
        Various parties including the OCC have intervened in this case and the case
        has
        been consolidated with the RCP application discussed below.
 
 On
        September 9,
        2005, OE filed an application with the PUCO that, if approved, would supplement
        its existing RSP with an RCP. On September 27, 2005, the PUCO granted
        FirstEnergy's motion to consolidate the GCAF rider application with the RCP
        proceedings and set hearings for the consolidated cases to begin
        November 29, 2005. The RCP is designed to provide customers with more
        certain rate levels than otherwise available under the RSP during the plan
        period, and to provide OE with financial results generally comparable to
        those
        attained under the RSP. Major provisions of the RCP include:
 
 · Maintain
        the
        existing level of base distribution rates through December 31, 2008 for
        OE;
 
 · Defer
        and
        capitalize 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;
 
 · Adjust
        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;
 
 · Reduce
        the deferred
        shopping incentive balance 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
 
 · Recover
        increased
        fuel costs 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 may defer and capitalize increased fuel costs above the amount
 collected
        through the
        fuel recovery mechanism.


76




Under
        provisions of
        the RSP, the PUCO may require OE to undertake, no more often than annually,
        a
        competitive bid process to secure generation for the years 2007 and 2008.
        On
        July 22, 2005, FirstEnergy filed a competitive
        bid
        process for the period beginning in 2007 that is similar to the competitive
        bid
        process approved by the PUCO for OE in 2004, which resulted in the PUCO
        accepting no bids. Any acceptance of future competitive bid results would
        terminate the RSP pricing, with no accounting impacts to the RSP, and not
        until
        twelve months after the PUCO authorizes such termination. On September 28,
        2005, the PUCO issued an Entry that essentially approved the Ohio Companies'
        filing but delayed the proposed timing of the competitive bid process by
        four
        months, calling for the auction to be held on March 21, 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 seeks recovery of these costs beginning January 1, 2006.
        At the
        time of filing the application, these costs were estimated to be approximately
        $14 million per year; however, OE anticipates that this amount will increase.
        OE
        requested that these costs be recovered through a rider that would be effective
        on January 1, 2006 and adjusted each July 1 thereafter. OE
        reached a
        settlement with OCC, PUCO staff, Industrial Energy Users - Ohio and OPAE.
        The
        only other party in this proceeding, Dominion Retail, Inc., agreed not to
        oppose
        the settlement. This settlement, which was filed with the PUCO on July 22,
        2005, provides for the rider recovery requested by OE, with carrying charges
        applied in the subsequent year’s rider for any over or under collection while
        the then-current rider is in effect. The PUCO approved the settlement
        stipulation on August 31, 2005. The incremental Transmission and Ancillary
        service revenues expected to be recovered from January through June 2006
        are
        approximately $30.6 million. This value includes the recovery of the 2005
        deferred MISO expenses as described below. In May 2006, OE will file a
        modification to the rider which will determine revenues from July 2006 through
        June 2007.
 
 The
        second
        application seeks 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 OE 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 31, 2004 was denied.
        The PUCO also authorized OE to accrue carrying charges on the deferred balances.
        An application filed with the PUCO to recover these deferred charges over
        a
        five-year period through the rider, beginning in 2006, was approved in a
        PUCO
        order issued on August 31, 2005 approving the stipulation referred
        to
        above. The OCC, OPAE and OE each filed applications for rehearing. OE sought
        authority to defer the transmission and ancillary service related costs incurred
        during the period October 1, 2003 through December 29, 2004, while
        both OCC
        and OPAE sought to have the PUCO deny deferral of all costs. On July 6,
        2005, the PUCO denied OE's and OCC’s applications and, at the request of OE,
        struck as untimely OPAE’s application. The OCC filed a notice of appeal with the
        Ohio Supreme Court on August 31, 2005. On September 30, 2005, in accordance
        with appellate procedure, the PUCO filed with the Ohio Supreme Court the
        record
        in this case. The Companies’ brief will be due thirty days after the OCC files
        its brief, which, absent any time extensions, must be filed no later than
        November 9, 2005.
 
 OE
        and Penn record
        as regulatory assets costs which have been authorized by the PUCO, the PPUC
        and
        the FERC for recovery from customers in future periods and, without such
        authorization, the costs would have been charged to income when incurred.
        OE’s
        regulatory assets as of September 30, 2005 and December 31, 2004,
        were $0.8
        billion and $1.1 billion, respectively. OE is deferring customer shopping
        incentives and interest costs as new regulatory assets in accordance with
        its
        transition and rate stabilization plans. These regulatory assets total $302
        million as of September 30, 2005 and, under the RSP, will be recovered
        through a surcharge rate equal to the RTC rate in effect when the transition
        costs have been fully recovered. See Note 14 “Regulatory Matters - Ohio” for the
        estimated net amortization of regulatory transition costs and deferred shopping
        incentive balances under the proposed RCP and current RSP. Penn's net regulatory
        asset components aggregate as net regulatory liabilities of approximately
        $48
        million and $18 million, and are included in Other Noncurrent Liabilities
        on the
        Consolidated Balance Sheet as of September 30, 2005 and December 31,
        2004, respectively.
 
 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 is recommending that the Request for Proposal process cover
        the
        period of January 1, 2007 through May 31, 2008. Under Pennsylvania's
        electric competition law, Penn is required to secure generation supply for
        customers who do not choose alternative suppliers for their
        electricity.
 
 See
        Note 14 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 actions by the PPUC, that impact
        Penn.





77


***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.
 
 FirstEnergy
        plans
        to issue a report regarding its response to air emission requirements.
        FirstEnergy expects to complete the report by December 1,
        2005.
 
 *National
        Ambient Air Quality Standards*
 
 In
        July 1997, the
        EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS for
        fine
        particulate matter. On March 10, 2005, the EPA finalized the "Clean
        Air
        Interstate Rule" covering a total of 28 states (including 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
        nonattainment 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 regulation 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 )
        in all cases from
        the 2003 levels. The OE Companies’ Ohio and Pennsylvania fossil-fuel generation
        facilities will be subject to the caps on SO 2 and 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 the OE Companies operate 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. On March 14, 2005, the
        EPA
        finalized the “Clean Air Mercury Rule,” 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 the CAIR and the Clean Air Mercury rule
        have
        been challenged in the United States Court of Appeals for the District of
        Columbia. Future cost of compliance with these regulations 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 is owned 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, which is in the form of a Consent
        Decree, was approved by the Court on July 11, 2005, requires OE and
        Penn to
        reduce NO x and SO 2 emissions at the
        W. H. Sammis Plant and other coal-fired plants through the installation of
        pollution control devices. Capital expenditures necessary to meet those
        requirements are currently estimated to be $1.5 billion (the primary portion
        of
        which is expected to be spent in the 2008 to 2011 time period). 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
        payable by OE and Penn of $7.8 million and $0.7 million, respectively. OE
        and
        Penn also recognized liabilities of $9.2 million and $0.8 million, respectively,
        for probable future cash contributions toward environmentally beneficial
        projects during the first quarter of 2005.




78


*Climate
        Change*
 
 In
        December 1997,
        delegates to the United Nations' climate summit in Japan adopted an agreement,
        the Kyoto Protocol (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 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 percent through 2012. The Energy
        Policy Act of 2005 established a Committee on Climate Change Technology to
        coordinate federal climate change activities and promote the development
        and
        deployment of GHG reducing technologies.
 
 The
        OE Companies
        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 KWH
        of electricity generated by the OE Companies is lower than many regional
        competitors due to the OE Companies' diversified generation sources which
        include low or non-CO 2 emitting
        gas-fired
        and nuclear generators.
 
 *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.
 
 See
        Note 13(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 material items not otherwise discussed above are
        described below.
 
 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 concludes, 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 website (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 also is proceeding with
        the
        implementation of the recommendations regarding enhancements to regional
        reliability 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, and therefore FirstEnergy has not accrued a liability as of
        September 30, 2005 for any expenditures in excess of those actually
        incurred through that date. FirstEnergy notes, however, that the FERC or
        other
        applicable government agencies and reliability coordinators may take a different
        view as to recommended enhancements or may recommend additional enhancements
        in
        the future that could require additional, material expenditures. Finally,
        the
        PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to
        control room computer hardware and software and enhancements to the training
        of
        control room operators, before determining the next steps, if any, in the
        proceeding.




79




FirstEnergy
        companies also are defending six separate complaint cases before the PUCO
        relating to the August 14, 2003 power outage. Two such cases were
        originally filed in Ohio State courts but subsequently dismissed for lack
        of
        subject matter jurisdiction and further appeals were unsuccessful. In both
        such
        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. Of the four other pending PUCO complaint cases, three were filed
        by
        various insurance carriers either in their own name as subrogees or in the
        name
        of their insured. In each such case, the carriers seek reimbursement against
        various FirstEnergy companies (and, in one case, against PJM, MISO and American
        Electric Power Co. as well) for claims they paid to their insureds allegedly
        due
        to 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 fourth
        case
        involves the claim of a non-customer seeking reimbursement for losses incurred
        when its store was burglarized on August 14, 2003. In addition to these six
        cases, the Ohio Companies were named as respondents in a regulatory proceeding
        that was initiated at the PUCO in response to complaints alleging failure
        to
        provide reasonable and adequate service stemming primarily from the
        August 14, 2003 power outages. No estimate of potential liability
        has been
        undertaken for any of these cases.
 
 One
        complaint was
        filed on August 25, 2004 against FirstEnergy in the New York State Supreme
        Court. In this case, several plaintiffs in the New York City metropolitan
        area
        allege that they suffered damages as a result of the August 14, 2003
        power
        outages. None of the plaintiffs are customers of any FirstEnergy affiliate.
        FirstEnergy's motion to dismiss the case was granted on September 26,
        2005.
        Additionally, FirstEnergy Corp. was named in a complaint filed in Michigan
        State
        Court by an individual who is not a customer of any FirstEnergy company.
        A
        responsive pleading to this matter is not due until on or about December
        1,
        2005. No estimate of potential liability has been undertaken in this matter.
 
 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.
 
 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 effective corrective action. FENOC operates the Perry Nuclear Power Plant,
        in which the OE Companies have a 35.24% interest (however, see Note 17 regarding
        FirstEnergy’s pending intra-system generation asset transfers, which include
        owned portions of the 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
        May 26,
        2005, the NRC held a public meeting to discuss its oversight of the Perry
        Plant.
        While the NRC stated that the plant continued to operate safely, the NRC
        also
        stated that the overall performance had not substantially improved since
        the
        heightened inspection was initiated. The
        NRC reiterated
        this conclusion in its mid-year assessment letter dated August 30, 2005.
        On
        September 28, 2005, the NRC sent a CAL to FENOC describing commitments
        that
        FENOC had made to improve the performance of Perry 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. 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. As a result, these matters could have a material adverse effect
        on
        FirstEnergy's or its subsidiaries' financial condition, results of operations
        and cash flows.
 
 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 OE, and the Davis-Besse extended outage (OE has no interest
        in
        Davis-Besse), 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 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. FirstEnergy
        has
        cooperated fully with the informal inquiry and will continue to do so with
        the
        formal investigation.


80




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 the 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.
 
 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. 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. It is unknown when the PUCO will rule on this case.
 
 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 13(C) to
        the consolidated financial statements for further details and a complete
        discussion of other legal proceedings.
 
 **New
        Accounting Standards and Interpretations**
 
 *EITF
        Issue
        04-13,”Accounting for Purchases and Sales of Inventory with the Same
        Counterparty”*
  In
        September 2005,
        the EITF reached a final consensus on Issue 04-13 concluding that two or
        more
        legally separate exchange transactions with the same counterparty should
        be
        combined and considered as a single arrangement for purposes of applying
        APB 29,
        when the transactions were entered into "in contemplation" of one another.
        If
        two transactions are combined and considered a single arrangement, the EITF
        reached a consensus that an exchange of inventory should be accounted for
        at
        fair value. Although electric power is not capable of being held in inventory,
        there is no substantive conceptual distinction between exchanges involving
        power
        and other storable inventory. Therefore, OE will adopt this EITF effective
        for
        new arrangements entered into, or modifications or renewals of existing
        arrangements, in interim or annual periods beginning after March 15, 2006.
 
 *EITF
                  Issue No. 05-6, “Determining the Amortization Period for Leasehold
                  Improvements Purchased after Lease Inception or Acquired in a Business
                  Combination”*
  In
        June 2005, the
        EITF reached a consensus on the application guidance for Issue 05-6. EITF
        05-6
        addresses the amortization period for leasehold improvements that were either
        acquired in a business combination or placed in service significantly after
        and
        not contemplated at or near the beginning of the initial lease term. For
        leasehold improvements acquired in a business combination, the amortization
        period is the shorter of the useful life of the assets or a term that includes
        required lease periods and renewals that are deemed to be reasonably assured
        at
        the date of acquisition. Leasehold improvements that are placed in service
        significantly after and not contemplated at or near the beginning of the
        lease
        term should be amortized over the shorter of the useful life of the assets
        or a
        term that includes required lease periods and renewals that are deemed to
        be
        reasonably assured at the date the leasehold improvements are purchased.
        This
        EITF was effective July 1, 2005 and is consistent with the OE current
        accounting.
 
 *FIN
                  47,
                  “Accounting for Conditional Asset Retirement Obligations - an
                  interpretation of FASB Statement No.
                  143”*
 
 On
        March 30,
        2005, the FASB issued FIN 47 to clarify the scope and timing of liability
        recognition for conditional asset retirement obligations. Under this
        interpretation, companies are required to recognize a liability for the fair
        value of an asset retirement obligation that is conditional on a future event,
        if the fair value of the liability can be reasonably estimated. In instances
        where there is insufficient information to estimate the liability, the
        obligation is to be recognized in the second period in which sufficient
        information becomes available to estimate its fair value. If the fair value
        cannot be reasonably estimated, that fact and the reasons why must be disclosed.
        This Interpretation is effective no later than the end of fiscal years ending
        after December 15, 2005. Therefore, OE will adopt this Interpretation
        in
        the fourth quarter of 2005. OE is currently evaluating the effect this standard
        will have on its financial statements.


81




*SFAS
                  154
                  - “Accounting Changes and Error Corrections - a replacement of APB
                  Opinion
                  No. 20 and FASB Statement No.
                  3”*
 
 In
        May 2005, the
        FASB issued SFAS 154 to change the requirements for accounting and reporting
        a
        change in accounting principle. It applies to all voluntary changes in
        accounting principle and to changes required by an accounting pronouncement
        when
        that pronouncement does not include specific transition provisions. This
        Statement requires retrospective application to prior periods’ financial
        statements of changes in accounting principle, unless it is impracticable
        to
        determine either the period-specific effects or the cumulative effect of
        the
        change. In those instances, this Statement requires that the new accounting
        principle be applied to the balances of assets and liabilities as of the
        beginning of the earliest period for which retrospective application is
        practicable and that a corresponding adjustment be made to the opening balance
        of retained earnings (or other appropriate components of equity or net assets
        in
        the statement of financial position) for that period rather than being reported
        in an income statement. This Statement also requires that a change in
        depreciation, amortization, or depletion method for long-lived, nonfinancial
        assets be accounted for as a change in accounting estimate affected by a
        change
        in accounting principle. The provisions of this Statement are effective for
        accounting changes and corrections of errors made in fiscal years beginning
        after December 15, 2005. OE will adopt this Statement effective January
        1,
        2006.
 
 *SFAS
                  153,
                  “Exchanges of Nonmonetary Assets - an amendment of APB Opinion No.
                  29”*
 
 In
        December 2004,
        the FASB issued SFAS 153 amending APB 29, which was based on the principle
        that
        nonmonetary assets should be measured based on the fair value of the assets
        exchanged. The guidance in APB 29 included certain exceptions to that principle.
        SFAS 153 eliminates the exception from fair value measurement for nonmonetary
        exchanges of similar productive assets and replaces it with an exception
        for
        exchanges that do not have commercial substance. This Statement specifies
        that a
        nonmonetary exchange has commercial substance if the future cash flows of
        the
        entity are expected to change significantly as a result of the exchange.
        The
        provisions of this Statement are effective for nonmonetary exchanges occurring
        in fiscal periods beginning after June 15, 2005 and are to be applied
        prospectively. As a result, OE will adopt this Statement effective
        January 1, 2006, and does not expect it to have a material impact
        on its
        financial statements.
 
 *SFAS
        151,
“Inventory Costs - an amendment of ARB No. 43, Chapter 4”*
 
 In
        November 2004,
        the FASB issued SFAS 151 to clarify the accounting for abnormal amounts of
        idle
        facility expense, freight, handling costs and wasted material (spoilage).
        Previous guidance stated that in some circumstances these costs may be “so
        abnormal” that they would require treatment as current period costs. SFAS 151
        requires abnormal amounts for these items to always be recorded as current
        period costs. In addition, this Statement requires that allocation of fixed
        production overheads to the cost of conversion be based on the normal capacity
        of the production facilities. The provisions of this statement are effective
        for
        inventory costs incurred by OE beginning January 1, 2006. OE is currently
        evaluating this Standard and does not expect it to have a material impact
        on the
        financial statements.
 
 *FSP
        FAS 115-1,
“The Meaning of Other-Than-Temporary Impairment and its Application to Certain
        Investments”*
 
 In
        September 2005,
        the FASB finalized and renamed EITF 03-1 and 03-1-a to FSP FAS 115-1. FSP
        FAS
        115-1 will (1) supersede Issue 03-1 and EITF topic No. D-44, "Recognition
        of
        Other Than Temporary Impairment upon the Planned Sale of a Security Whose
        Cost
        Exceeds Fair Value," (2) clarify that an investor should recognize an impairment
        loss no later than when the impairment is deemed other than temporary, even
        if a
        decision to sell has not been made, and (3) be effective for
        other-than-temporary impairment and analyses conducted in periods beginning
        after September 15, 2005. The FASB expects to issue this FSP in the
        fourth
        quarter of 2005, which would require prospective application with an effective
        date for reporting periods beginning after December 15, 2005. OE is currently
        evaluating this FSP and any impact on its investments.


82






**THE
                    CLEVELAND ELECTRIC ILLUMINATING COMPANY****CONSOLIDATED
                    STATEMENTS OF INCOME AND COMPREHENSIVE INCOME****(Unaudited)****Three
                    Months Ended**
                
                
                
                **Nine
                    Months Ended****September
                    30,**
                
                
                
                **September
                    30,****2005**
                
                **2004**
                
                
                
                **2005**
                
                **2004*****(In
                    thousands)*****STATEMENTS
                    OF INCOME****OPERATING
                    REVENUES**
                
                $
                526,421
                
                $
                504,848
                
                
                
                $
                1,408,341
                
                $
                1,372,259**OPERATING
                    EXPENSES AND TAXES:**Fuel
                
                
                24,701
                
                
                21,011
                
                
                
                
                64,138
                
                
                57,583Purchased
                    power
                
                
                129,640
                
                
                140,988
                
                
                
                
                411,366
                
                
                412,170Nuclear
                    operating costs
                
                
                26,252
                
                
                28,766
                
                
                
                
                121,765
                
                
                80,002Other
                    operating costs
                
                
                89,475
                
                
                76,196
                
                
                
                
                227,759
                
                
                219,857Provision
                    for
                    depreciation
                
                
                36,100
                
                
                33,096
                
                
                
                
                100,602
                
                
                98,060Amortization
                    of regulatory assets
                
                
                68,455
                
                
                53,732
                
                
                
                
                177,497
                
                
                151,822Deferral
                    of
                    new regulatory assets
                
                
                (60,519
                )
                
                (40,596
                )
                
                
                
                (126,508
                )
                
                (92,032
                )General
                    taxes
                
                
                40,054
                
                
                37,348
                
                
                
                
                115,546
                
                
                110,646Income
                    taxes
                
                
                55,286
                
                
                51,883
                
                
                
                
                94,897
                
                
                81,057Total
                    operating expenses and taxes
                
                
                409,444
                
                
                402,424
                
                
                
                
                1,187,062
                
                
                1,119,165**OPERATING
                    INCOME**
                
                
                116,977
                
                
                102,424
                
                
                
                
                221,279
                
                
                253,094**OTHER
                    INCOME (net of income taxes)**
                
                
                24,117
                
                
                8,264
                
                
                
                
                37,691
                
                
                29,485**NET
                    INTEREST CHARGES:**Interest
                    on
                    long-term debt
                
                
                27,090
                
                
                24,061
                
                
                
                
                83,452
                
                
                92,967Allowance
                    for
                    borrowed funds used during construction
                
                
                (1,129
                )
                
                (1,056
                )
                
                
                
                (2,012
                )
                
                (3,782
                )Other
                    interest expense
                
                
                4,696
                
                
                5,239
                
                
                
                
                12,952
                
                
                12,750Net
                    interest
                    charges
                
                
                30,657
                
                
                28,244
                
                
                
                
                94,392
                
                
                101,935**NET
                    INCOME**
                
                
                110,437
                
                
                82,444
                
                
                
                
                164,578
                
                
                180,644**PREFERRED
                    STOCK DIVIDEND REQUIREMENTS**
                
                
                -
                
                
                1,754
                
                
                
                
                2,918
                
                
                5,253**EARNINGS
                    ON COMMON STOCK**
                
                $
                110,437
                
                $
                80,690
                
                
                
                $
                161,660
                
                $
                175,391**STATEMENTS
                    OF COMPREHENSIVE INCOME****NET
                    INCOME**
                
                $
                110,437
                
                $
                82,444
                
                
                
                $
                164,578
                
                $
                180,644**OTHER
                    COMPREHENSIVE INCOME (LOSS):**Unrealized
                    gain (loss) on available for sale securities
                
                
                (6,574
                )
                
                991
                
                
                
                
                (9,144
                )
                
                (1,332
                )Income
                    tax
                    expense (benefit) related to other comprehensive income
                
                
                (2,510
                )
                
                406
                
                
                
                
                (3,433
                )
                
                (546
                )Other
                    comprehensive income (loss), net of tax
                
                
                (4,064
                )
                
                585
                
                
                
                
                (5,711
                )
                
                (786
                )**TOTAL
                    COMPREHENSIVE INCOME**
                
                $
                106,373
                
                $
                83,029
                
                
                
                $
                158,867
                
                $
                179,858The
                    preceding
                    Notes to Consolidated Financial Statements as they relate to
                    The Cleveland
                    Electric Illuminating Company are anintegral
                    part
                    of these statements.
    83
  **THE
                    CLEVELAND ELECTRIC ILLUMINATING COMPANY****CONSOLIDATED
                    BALANCE SHEETS****(Unaudited)****September
                    30,**
                
                **December
                    31,****2005**
                
                **2004*****(In
                    thousands)*****ASSETS****UTILITY
                    PLANT:**In
                    service
                
                $
                4,498,876
                
                $
                4,418,313Less
                    -
                    Accumulated provision for depreciation
                
                
                2,020,868
                
                
                1,961,7372,478,008
                
                
                2,456,576Construction
                    work in progress -Electric
                    plant
                
                
                90,911
                
                
                85,258Nuclear
                    fuel
                
                
                8,632
                
                
                30,82799,543
                
                
                116,0852,577,551
                
                
                2,572,661**OTHER
                    PROPERTY AND INVESTMENTS:**Investment
                    in
                    lessor notes
                
                
                564,169
                
                
                596,645Nuclear
                    plant
                    decommissioning trusts
                
                
                427,920
                
                
                383,875Long-term
                    notes receivable from associated companies
                
                
                8,774
                
                
                97,489Other
                
                
                16,028
                
                
                17,0011,016,891
                
                
                1,095,010**CURRENT
                    ASSETS:**Cash
                    and cash
                    equivalents
                
                
                207
                
                
                197Receivables-Customers
                    (less accumulated provision of $5,309,000 for uncollectible accounts
                    in
                    2005)
                
                
                255,769
                
                
                11,537Associated
                    companies
                
                
                19,883
                
                
                33,414Other
                    (less
                    accumulated provisions of $6,000 and $293,000, respectively,
                
                
                9,651
                
                
                152,785for
                    uncollectible accounts)Notes
                    receivable from associated companies
                
                
                -
                
                
                521Materials
                    and
                    supplies, at average cost
                
                
                72,506
                
                
                58,922Prepayments
                    and other
                
                
                2,769
                
                
                2,136360,785
                
                
                259,512**DEFERRED
                    CHARGES:**Goodwill
                
                
                1,688,966
                
                
                1,693,629Regulatory
                    assets
                
                
                889,127
                
                
                958,986Property
                    taxes
                
                
                77,792
                
                
                77,792Other
                
                
                29,995
                
                
                32,8752,685,880
                
                
                2,763,282$
                6,641,107
                
                $
                6,690,465**CAPITALIZATION
                    AND LIABILITIES****CAPITALIZATION:**Common
                    stockholder's equity-Common
                    stock,
                    without par value, authorized 105,000,000 shares -79,590,689
                    shares outstanding
                
                $
                1,356,998
                
                $
                1,281,962Accumulated
                    other comprehensive income
                
                
                12,148
                
                
                17,859Retained
                    earnings
                
                
                574,394
                
                
                553,740Total
                    common
                    stockholder's equity
                
                
                1,943,540
                
                
                1,853,561Preferred
                    stock
                
                
                -
                
                
                96,404Long-term
                    debt
                    and other long-term obligations
                
                
                1,939,730
                
                
                1,970,1173,883,270
                
                
                3,920,082**CURRENT
                    LIABILITIES:**Currently
                    payable long-term debt
                
                
                75,706
                
                
                76,701Short-term
                    borrowings-Associated
                    companies
                
                
                518,784
                
                
                488,633Other
                
                
                35,000
                
                
                -Accounts
                    payable-Associated
                    companies
                
                
                33,802
                
                
                150,141Other
                
                
                6,702
                
                
                9,271Accrued
                    taxes
                
                
                156,630
                
                
                129,454Accrued
                    interest
                
                
                27,242
                
                
                22,102Lease
                    market
                    valuation liability
                
                
                60,200
                
                
                60,200Other
                
                
                39,094
                
                
                61,131953,160
                
                
                997,633**NONCURRENT
                    LIABILITIES:**Accumulated
                    deferred income taxes
                
                
                552,072
                
                
                540,211Accumulated
                    deferred investment tax credits
                
                
                58,736
                
                
                60,901Lease
                    market
                    valuation liability
                
                
                623,100
                
                
                668,200Asset
                    retirement obligation
                
                
                280,765
                
                
                272,123Retirement
                    benefits
                
                
                86,597
                
                
                82,306Other
                
                
                203,407
                
                
                149,0091,804,677
                
                
                1,772,750**COMMITMENTS
                    AND CONTINGENCIES (Note 13)**$
                6,641,107
                
                $
                6,690,465The
                    preceding
                    Notes to Consolidated Financial Statements as they relate to
                    The Cleveland
                    Electric Illuminating Company arean
                    integral
                    part of these balance sheets.
 84
   **THE
                    CLEVELAND ELECTRIC ILLUMINATING COMPANY****CONSOLIDATED
                    STATEMENTS OF CASH FLOWS****(Unaudited)****Three
                    Months Ended**
                
                **Nine
                    Months Ended****September
                    30,**
                
                **September
                    30,****2005**
                
                **2004**
                
                **2005**
                
                **2004*****(In
                    thousands)*****CASH
                    FLOWS FROM OPERATING ACTIVITIES:**Net
                    income
                
                $
                110,437
                
                $
                82,444
                
                $
                164,578
                
                $
                180,644Adjustments
                    to reconcile net income to net cash fromoperating
                    activities -Provision
                    for
                    depreciation
                
                
                36,100
                
                
                33,096
                
                
                100,602
                
                
                98,060Amortization
                    of regulatory assets
                
                
                68,455
                
                
                53,732
                
                
                177,497
                
                
                151,822Deferral
                    of
                    new regulatory assets
                
                
                (60,519
                )
                
                (40,596
                )
                
                (126,508
                )
                
                (92,032
                )Nuclear
                    fuel
                    and capital lease amortization
                
                
                8,236
                
                
                7,804
                
                
                19,017
                
                
                20,420Amortization
                    of electric service obligation
                
                
                (2,155
                )
                
                (3,336
                )
                
                (12,278
                )
                
                (12,877
                )Deferred
                    rents and lease market valuation liability
                
                
                (13,439
                )
                
                (14,324
                )
                
                (67,130
                )
                
                (56,182
                )Deferred
                    income taxes and investment tax credits, net
                
                
                10,484
                
                
                13,019
                
                
                14,934
                
                
                11,392Accrued
                    retirement benefit obligations
                
                
                2,169
                
                
                2,854
                
                
                4,291
                
                
                10,900Accrued
                    compensation, net
                
                
                1,201
                
                
                1,303
                
                
                (1,294
                )
                
                3,232Pension
                    trust
                    contribution
                
                
                -
                
                
                (31,718
                )
                
                -
                
                
                (31,718
                )Decrease
                    (increase) in operating assets-Receivables
                
                
                10,507
                
                
                (3,422
                )
                
                (87,567
                )
                
                106,421Materials
                    and
                    supplies
                
                
                15,207
                
                
                (2,238
                )
                
                (13,584
                )
                
                (7,711
                )Prepayments
                    and other current assets
                
                
                (821
                )
                
                1,512
                
                
                (633
                )
                
                3,409Increase
                    (decrease) in operating liabilities-Accounts
                    payable
                
                
                (157,188
                )
                
                60,237
                
                
                (118,908
                )
                
                1,889Accrued
                    taxes
                
                
                33,955
                
                
                (15,630
                )
                
                27,176
                
                
                (52,495
                )Accrued
                    interest
                
                
                5,460
                
                
                (3,218
                )
                
                5,140
                
                
                (2,371
                )Prepayment
                    for electric service - education programs
                
                
                -
                
                
                -
                
                
                67,589
                
                
                -Other
                
                
                (18,457
                )
                
                (3,335
                )
                
                (26,328
                )
                
                (40,193
                )Net
                    cash
                    provided from operating activities
                
                
                49,632
                
                
                138,184
                
                
                126,594
                
                
                292,610**CASH
                    FLOWS FROM FINANCING ACTIVITIES:**New
                    Financing-Long-term
                    debt
                
                
                87,772
                
                
                44,330
                
                
                141,056
                
                
                125,238Short-term
                    borrowings, net
                
                
                -
                
                
                213,682
                
                
                53,369
                
                
                132,770Equity
                    contributions from parent
                
                
                -
                
                
                -
                
                
                75,000
                
                
                -Redemptions
                    and Repayments-Preferred
                    stock
                
                
                -
                
                
                (1,000
                )
                
                (101,900
                )
                
                (1,000
                )Long-term
                    debt
                
                
                (90,859
                )
                
                (327,171
                )
                
                (147,789
                )
                
                (335,272
                )Short-term
                    borrowings, net
                
                
                (5,505
                )
                
                -
                
                
                -
                
                
                -Dividend
                    Payments-Common
                    stock
                
                
                (17,000
                )
                
                -
                
                
                (141,000
                )
                
                (145,000
                )Preferred
                    stock
                
                
                -
                
                
                (1,755
                )
                
                (2,260
                )
                
                (5,253
                )Net
                    cash used
                    for financing activities
                
                
                (25,592
                )
                
                (71,914
                )
                
                (123,524
                )
                
                (228,517
                )**CASH
                    FLOWS FROM INVESTING ACTIVITIES:**Property
                    additions
                
                
                (37,809
                )
                
                (32,238
                )
                
                (98,053
                )
                
                (70,967
                )Loan
                    repayments from (loans to) associated companies, net
                
                
                22,309
                
                
                (850
                )
                
                89,236
                
                
                9,964Investments
                    in lessor notes
                
                
                3
                
                
                (11,699
                )
                
                32,476
                
                
                9,266Contributions
                    to nuclear decommissioning trusts
                
                
                (7,256
                )
                
                (7,256
                )
                
                (21,768
                )
                
                (21,768
                )Other
                
                
                (1,287
                )
                
                (14,227
                )
                
                (4,951
                )
                
                (15,170
                )Net
                    cash used
                    for investing activities
                
                
                (24,040
                )
                
                (66,270
                )
                
                (3,060
                )
                
                (88,675
                )Net
                    change in
                    cash and cash equivalents
                
                
                -
                
                
                -
                
                
                10
                
                
                (24,582
                )Cash
                    and cash
                    equivalents at beginning of period
                
                
                207
                
                
                200
                
                
                197
                
                
                24,782Cash
                    and cash
                    equivalents at end of period
                
                $
                207
                
                $
                200
                
                $
                207
                
                $
                200The
                    preceding
                    Notes to Consolidated Financial Statements as they relate to
                    The Cleveland
                    Electric Illuminating Company are anintegral
                    part
                    of these statements.
    85




***Report
        of Independent Registered Public Accounting Firm***
 
 
 
 
 
 
 
 
 
 To
        the Stockholders
        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, 2005, and the
        related consolidated statements of income and comprehensive income and cash
        flows for each of the three-month and nine-month periods ended September
        30,
        2005 and 2004. 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
        previously
        audited, in accordance with the standards of the Public Company Accounting
        Oversight Board (United States), the consolidated balance sheet as of
        December 31, 2004, and the related consolidated statements of income,
        capitalization, common stockholder’s 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,
        2004 and the effectiveness of the Company’s internal control over financial
        reporting as of December 31, 2004; 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) 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 March 7, 2005, 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 information as of December 31,
        2004, is fairly stated in all material respects in relation to the consolidated
        balance sheet from which it has been derived.
 
 
 
 
 PricewaterhouseCoopers
        LLP
 Cleveland,
        Ohio
 November
        1,
        2005




86




**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 provides power directly to alternative energy suppliers
        under CEI’s transition plan. CEI has unbundled the price of electricity into its
        component elements -- including generation, transmission, distribution and
        transition charges. Power supply requirements of CEI are provided by FES
        -- an
        affiliated company.
 
 **Results
        of Operations**
  Earnings
        on common
        stock in the third quarter of 2005 increased to $110 million from $81 million
        in
        the third quarter of 2005. Increased earnings in the third quarter of 2005
        resulted primarily from higher operating revenues and lower purchased power
        costs, which were partially offset by higher regulatory asset amortization
        and
        higher other operating costs. For the first nine months of 2005, earnings
        on
        common stock decreased to $162 million from $175 million in the same period
        of
        2004. Lower earnings for the first nine months of 2005 resulted primarily
        from
        higher nuclear operating costs, higher regulatory asset amortization and
        other
        operating costs and a one-time income tax charge; those effects were partially
        offset by increased operating revenues and lower net interest
        charges.
 
 Operating
        revenues
        increased by $22 million or 4.3% in the third quarter of 2005 from the same
        period in 2004. Higher revenues resulted primarily from increases in retail
        generation and distribution revenues of $3 million and $19 million,
        respectively, and a $5 million increase in revenues from wholesale sales.
        During
        the first nine months of 2005, operating revenues increased by $36 million
        or 2.6%,
        compared to the same period in 2004. Higher revenues were due to increases
        in
        retail generation and distribution revenues of $13 million and $23 million,
        respectively, and a $2 million increase in revenues from wholesale
        sales.
 
 Increased
        retail
        generation revenues for the third quarter of 2005 resulted from higher
        industrial unit prices and higher residential KWH sales, partially offset
        by
        lower unit prices and KWH sales for commercial customers. An 18.7% increase
        in
        residential KWH sales during the third quarter was primarily due to warmer
        weather in CEI's service area, as compared to last year. An increase in
        residential customer shopping by 1.7 percentage points in the third quarter
        of
        2005 partially offset the higher generation KWH sales as compared to 2004.
        Increased retail generation revenues for the first nine months of 2005 resulted
        from higher industrial unit prices and higher residential KWH sales, partially
        offset by lower commercial and industrial KWH sales. The decrease in residential
        customer shopping by 0.7 percentage points in the first nine months of 2005
        contributed slightly to the higher generation KWH sales for the period as
        compared to last year.
 
 Revenue
        from
        wholesale sales increased by $5 million during the third quarter of 2005,
        reflecting the effect of a 2.5% increase in KWH sales. The increase in wholesale
        sales was primarily due to a 13.6% KWH increase in MSG sales to non-affiliated
        wholesale customers ($3.5 million). Under its Ohio transition plan, CEI is
        required to provide MSG to non-affiliated alternative suppliers (see Outlook
        -
        Regulatory Matters). Increased sales to FES of $1.5 million (1.3% KWH increase)
        also contributed to the third quarter results. In the first nine months of
        2005,
        wholesale sales revenue increased by $2 million. A $20 million increase (23.0%
        KWH increase) in MSG sales to non-affiliated wholesale customers was partially
        offset by an $18 million decrease in sales (6.7% KWH decrease) to
        FES.
 
 Revenues
        from
        distribution throughput increased $19 million in the third quarter of 2005
        compared with the same quarter of 2004. The increase was due to higher
        residential and industrial revenues ($18 million and $5 million, respectively),
        reflecting increased distribution deliveries in the third quarter of 2005,
        in
        part due to warmer weather. These increases were partially offset by lower
        commercial revenues of $4 million as a result of lower unit prices.
 
 Revenues
        from
        distribution throughput increased $23 million in the first nine months of
        2005
        compared with the same period in 2004 due to higher revenues in the residential
        sector ($28 million), partially offset by lower industrial revenues ($4
        million). Higher distribution deliveries in the residential sector were
        partially offset by lower unit prices and decreased KWH deliveries to industrial
        customers. Revenues in the commercial sector increased slightly ($0.4 million)
        as higher distribution deliveries were almost totally offset by lower unit
        prices.







87





Changes
        in KWH
        sales by customer class in the three months and nine months ended
        September 30, 2005 from the corresponding periods of 2004 are summarized
        in
        the following table:




**Three**
            
            **Nine****Changes
                in KWH Sales**
            
            **Months**
            
            **Months****Increase
                (Decrease)**Electric
                Generation:Retail
            
            
            0.6
            %
            
            (0.3
            )%Wholesale
            
            
            2.5
            %
            
            (4.0
            )%**Total
                Electric Generation Sales**
            
            
            **1.7**
            **%**
            
            **(2.5**
            **)%**Distribution
                Deliveries:Residential
            
            
            18.7
            %
            
            9.7
            %Commercial
            
            
            1.5
            %
            
            3.3
            %Industrial
            
            
            2.8
            %
            
            (1.0
            )%**Total
                Distribution Deliveries**
            
            
            **6.6**
            **%**
            
            **2.9**
            **%**





*Operating
        Expenses and Taxes*
 
 Total
        operating
        expenses and taxes increased by $7 million in the third quarter and $68 million
        in the first nine months of 2005 from the same periods of 2004. The following
        table presents changes from the prior year by expense
        category.


**Three**
            
            **Nine****Operating
                Expenses and Taxes - Changes**
            
            **Months**
            
            **Months****Increase
                (Decrease)**
            
            ***(In
                millions)***Fuel
                costs
            
            $
            3
            
            $
            6Purchased
                power costs
            
            
            (11
            )
            
            (1
            )Nuclear
                operating costs
            
            
            (2
            )
            
            42Other
                operating costs
            
            
            13
            
            
            8Provision
                for
                depreciation
            
            
            3
            
            
            3Amortization
                of regulatory assets
            
            
            15
            
            
            26Deferral
                of
                new regulatory assets
            
            
            (20
            )
            
            (35
            )General
                taxes
            
            
            3
            
            
            5Income
                taxes
            
            
            3
            
            
            14**Net
                increase in operating expenses and taxes**
            
            $
            7
            
            $
            68





Higher
        fuel costs
        in the third quarter and first nine months of 2005, compared to the same
        periods
        last year, were primarily due to increased fossil fuel expenses associated
        with
        higher fossil generation levels in 2005. Lower purchased power costs in the
        third quarter of 2005, compared with the third quarter of 2004, reflected
        both
        lower unit costs and lower KWH purchased. The increase in nuclear operating
        costs in the first nine months of 2005, compared to the same period last
        year,
        was primarily due to a refueling outage (including an unplanned extension)
        at
        the Perry Plant in 2005 and a refueling outage at Beaver Valley Unit 2. A
        mid-cycle inspection outage at the Davis-Besse Plant in the first quarter
        of
        2005 also contributed to higher nuclear operating costs in the first nine
        months
        of 2005. There were no scheduled outages in the first nine months of 2004.
        Higher other operating costs in the third quarter and first nine months of
        2005,
        compared to the same periods last year, were primarily due to transmission
        expenses related to MISO Day 2 transactions that began on April 1, 2005.
 
 Higher
        regulatory
        asset amortization in the third quarter and first nine months of 2005, compared
        to the same periods last year, was primarily due to increased amortization
        of
        transition costs being recovered under the RSP. Increases in regulatory asset
        deferrals for both the third quarter and first nine months in 2005, compared
        to
        the same periods in 2004, resulted from higher shopping incentive deferrals
        and
        related interest, and the PUCO-approved MISO administrative cost deferrals,
        including interest, that began in the second quarter of 2005 (see Outlook
        -
        Regulatory Matters).
 
 On
        June 30, 2005,
        the State of Ohio enacted new tax legislation that create d
        a new CAT tax,
        which is based on qualifying “taxable gross receipts” and will not consider any
        expenses or costs incurred to generate such receipts, except for items such
        as
        cash discounts, returns and allowances, and bad debts. The CAT tax was effective
        July 1, 2005, and replaces the Ohio income-based franchise tax and
        the Ohio
        personal property tax. The CAT tax is phased-in while the current income-based
        franchise tax is phased-out over a five-year period at a rate of 20% annually,
        beginning with the year ended 2005, and personal property tax is phased-out
        over
        a four-year period at a rate of 25% annually, beginning with the year ended
        2005. For example, during the phase-out period the Ohio income-based franchise
        tax will be computed consistently with prior tax law, except that the tax
        liability as computed will be multiplied by 4/5 in 2005; 3/5 in 2006; 2/5
        in
        2007 and 1/5 in 2008, therefore eliminating the current income-based franchise
        tax over a five-year period. As a result of the new tax structure, all net
        deferred tax benefits that are not expected to reverse during the five-year
        phase-in period were written-off as of June 30, 2005. The impact on
        income
        taxes associated with the new tax legislation for the first nine months of
        2005
        was additional tax expense of approximately $8 million to adjust net deferred
        taxes and $2 million associated with the phase-out of the Ohio income-based
        franchise tax. See Note 12 to the consolidated financial
        statements.


88


*Other
        Income*
 
 Other
        income
        increased by $16 million in the third quarter of 2005 compared with the same
        period of 2004, primarily due to higher nuclear decommissioning trust realized
        gains.
 
 *Net
        Interest
        Charges*
 
 Net
        interest
        charges in the first nine months of 2005 decreased by $8 million compared
        with
        the same period last year, reflecting the effects of net redemptions and
        refinancings since October 1, 2004.
 
 **Capital
        Resources and Liquidity**
    CEI’s
          cash
          requirements for the remainder of 2005 for operating expenses and construction
          expenditures are expected to be met without increasing net debt. 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,
        2005, CEI had $207,000 of cash and cash equivalents, compared with $197,000
        as
        of December 31, 2004. The major sources of changes in these balances
        are
        summarized below.
 
 *Cash
        Flows from
        Operating Activities*
 
 Cash
        provided by
        operating activities during the third quarter and first nine months of 2005,
        compared with the corresponding periods in 2004, were as follows:


**Three
                Months Ended**
            
            **Nine
                Months Ended****September
                30,**
            
            **September
                30,****Operating
                Cash Flows**
            
            **2005**
            
            **2004**
            
            **2005**
            
            **2004*****(In
                millions)***Cash
                earnings(1)
            
            $
            161
            
            $
            123
            
            $
            274
            
            $
            302Pension
                trust
                contribution(2)
            
            
            --
            
            
            (19
            )
            
            --
            
            
            (19
            )Working
                capital and other
            
            
            (111
            )
            
            35
            
            
            (147
            )
            
            10Total
                cash
                flows from operating activities
            
            $
            50
            
            $
            139
            
            $
            127
            
            $
            293(1)Cash
                earnings is a non-GAAP measure (see reconciliation below).
              (2)Pension
                contribution net of $13 million of income tax benefits




Cash
        earnings, as
        disclosed 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. The following table reconciles
        cash earnings with net income.


89








**Three
                Months Ended**
            
            **Nine
                Months Ended****September
                30,**
            
            **September
                30,****Reconciliation
                of Cash Earnings**
            
            **2005**
            
            **2004**
            
            **2005**
            
            **2004*****(In
                millions)***Net
                income
                (GAAP)
            
            $
            110
            
            $
            83
            
            $
            164
            
            $
            181Non-cash
                charges (credits):Provision
                for
                depreciation
            
            
            36
            
            
            33
            
            
            101
            
            
            98Amortization
                of regulatory assets
            
            
            68
            
            
            54
            
            
            177
            
            
            152Deferral
                of
                new regulatory assets
            
            
            (60
            )
            
            (41
            )
            
            (126
            )
            
            (92
            )Nuclear
                fuel
                and capital lease amortization
            
            
            8
            
            
            7
            
            
            19
            
            
            20Amortization
                of electric service obligation
            
            
            (2
            )
            
            (3
            )
            
            (12
            )
            
            (13
            )Deferred
                rents and lease market valuation liability
            
            
            (13
            )
            
            (14
            )
            
            (67
            )
            
            (56
            )Deferred
                income taxes and investment tax credits, net
            
            
            10
            
            
            --
            
            
            15
            
            
            (2
            )Accrued
                retirement benefit obligations
            
            
            2
            
            
            3
            
            
            4
            
            
            11Accrued
                compensation, net
            
            
            2
            
            
            1
            
            
            (1
            )
            
            3Cash
                earnings
                (Non-GAAP)
            
            $
            161
            
            $
            123
            
            $
            274
            
            $
            302





The
        increase in
        cash earnings of $38 million for the third quarter and the decrease of $28
        million for the first nine months of 2005, as compared to the respective
        periods
        of 2004, are described above under "Results of Operations". The primary factors
        contributing to the changes in working capital and other for the third quarter
        of 2005 are changes in accounts payable of $217 million, partially offset
        by
        changes in accrued taxes of $50 million. The primary factors contributing
        to the
        changes in working capital and other for the first nine months of 2005 are
        changes in accounts receivable of $194 million and accounts payable of $121
        million, partially offset by changes in accrued taxes of $80 million and
        the $68
        million received in the second quarter of 2005 for prepaid electric service
        under the Ohio Schools Council’s Energy for Education Program.
 
 *Cash
        Flows from
        Financing Activities*
  Net
        cash used for
        financing activities decreased $46 million in the third quarter of 2005 from
        the
        third quarter of 2004. The decrease resulted from a $62 million decrease
        in net
        debt redemptions, partially offset by higher common stock dividends to
        FirstEnergy of $17 million. Net
        cash used for
        financing activities decreased $105 million in the first nine months of 2005
        from the same period last year. The decrease resulted primarily from lower net
        debt redemptions and common stock dividends to FirstEnergy and a
        $75 million
        equity contribution from FirstEnergy in the second quarter of 2005, partially
        offset by an increase in preferred stock redemptions.
 
 CEI
        had $207,000 of
        cash and temporary investments and approximately $554 million of short-term
        indebtedness as of September 30, 2005. CEI has obtained authorization from
        the
        PUCO to incur short-term debt of up to $500 million (including the utility
        money
        pool described below). As of October 24, 2005, CEI had the capability to
        issue
        $1.6 billion of additional FMB on the basis of property additions and retired
        bonds under the terms of its mortgage indenture following
        the
        recently completed intra-system transfer of fossil and hydroelectric generating
        plants (See Note 17). 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, this provision would permit CEI to incur additional secured debt
        not
        otherwise permitted by a specified exception of up to $582 million as of
        September 30, 2005. 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,
        2005,
        the facility was drawn for $35 million.
 
 On
        June 14,
        2005, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI,
        as Borrowers, entered into a syndicated $2 billion five-year revolving credit
        facility. Borrowings under the facility are available to each Borrower
        separately and will mature on the earlier of 364 days from the date of borrowing
        and the commitment termination date, as the same may be extended. CEI’s
        borrowing limit under the facility is $250 million.


90




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 third quarter of 2005 was
        3.50%.
 
 CEI’s
        access to
        capital markets and costs of financing are dependent on the ratings of its
        securities and the securities of FirstEnergy.
 
 On
        July 18,
        2005, Moody’s revised its rating outlook on FirstEnergy and its subsidiaries to
        positive from stable. Moody’s stated that the revision to FirstEnergy’s outlook
        resulted from steady financial improvement and steps taken by management
        to
        improve operations, including the stabilization of its nuclear operations.
        Moody’s further stated that the revision in their outlook recognized
        management’s regional strategy of focusing on its core utility businesses and
        the improvement in FirstEnergy’s credit profile stemming from the application of
        free cash flow toward debt reduction. Moody’s noted that a ratings upgrade could
        be considered if FirstEnergy continues to achieve planned improvements in
        its
        operations and balance sheet.
 
 On
        October 3,
        2005, S&P raised its corporate credit rating on FirstEnergy and the EUOC to
        'BBB' from 'BBB-'. At the same time, S&P raised the senior unsecured ratings
        at the holding company to 'BBB-' from 'BB+' and each of the EUOC by one notch
        above the previous rating. S&P noted that the upgrade followed the
        continuation of a good operating track record, specifically for the nuclear
        fleet through the third quarter 2005. S&P also stated that FirstEnergy’s
        rating reflects the benefits of supportive regulation, low-cost base load
        generation fleet, low-risk transmission and distribution operations and rate
        certainty in Ohio. FirstEnergy’s ability to consistently generate free cash
        flow, good liquidity, and an improving financial profile were also noted
        as
        strengths.
 
 *Cash
        Flows from
        Investing Activities*
 
 In
        the third
        quarter and first nine months of 2005, net cash used for investing activities
        decreased $42 million and $86 million, respectively, from the corresponding
        periods of 2004. The decrease in funds used for investing activities for
        both
        periods primarily reflected increases in loan payments received from associated
        companies, partially offset by increased property additions.
 
 In
        the last quarter
        of 2005, capital requirements for property additions are expected to be about
        $37 million. These cash requirements are expected to be satisfied from internal
        cash and short-term credit arrangements. CEI has no additional requirements
        for
        sinking fund requirements for preferred stock and debt during the remainder
        of
        2005. CEI’s capital spending for the period 2005-2007 is expected to be about
        $368 million of which approximately $124 million applies to 2005.
 
 **FirstEnergy
        Intra-System Generation Asset Transfers**
  On
        May 18,
        2005, OE, CEI and TE, entered into certain agreements implementing a series
        of
        intra-system generation asset transfers. When fully completed, the asset
        transfers will result in the respective undivided ownership interests of
        the
        Ohio Companies in FirstEnergy’s nuclear and non-nuclear plants being owned by
        NGC, and FGCO, respectively. The generating plant interests that are being
        transferred do 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 transfer of non-nuclear generation assets to FGCO. CEI
        currently expects to complete the transfer of nuclear
        generation assets to NGC at book value before the end of 2005. Consummation
        of
        the nuclear transfer remains subject to necessary regulatory
        approvals.
 
 These
        transactions
        are being undertaken in connection with the Ohio Companies’ restructuring plans
        that were approved by the PUCO under applicable Ohio electric utility
        restructuring legislation. Consistent with the restructuring plans, generation
        assets that had been owned by the Ohio Companies were required to be separated
        from the regulated delivery business of those companies through transfer
        to a
        separate corporate entity. FENOC currently operates and maintains the nuclear
        generation assets to be transferred. FGCO, as lessee under a Master Facility
        Lease, leased, operated and maintained the non-nuclear generation assets
        that it
        now owns. The transactions will essentially complete the divestitures
        contemplated by the restructuring plans by transferring the ownership interests
        to NGC and FGCO, respectively, without impacting the operation of the plants.
  See
        Note 17 to the
        consolidated financial statements for CEI’s disclosure of the assets held for
        sale as of September 30, 2005.


91


**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,
        2005, the present value of these operating lease commitments, net of trust
        investments, total $103 million.
 
 CEI
        sells
        substantially all of its retail customer receivables to CFC, its wholly owned
        subsidiary. As of June 16, 2005, the CFC receivables financing structure
        was renewed and restructured from an off-balance sheet transaction to an
        on-balance sheet transaction. Under the new structure, any borrowings under
        the
        facility appear on the balance sheet as short-term debt.
 
 **Equity
        Price Risk**
  Included
        in CEI’s
        nuclear decommissioning trust investments are marketable equity securities
        carried at their market value of approximately $277 million and $242 million
        as
        of September 30, 2005 and December 31, 2004, respectively. A hypothetical
        10% decrease in prices quoted by stock exchanges would result in a $28 million
        reduction in fair value as of September 30, 2005.
 
 **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.
 
 ***Regulatory
        Matters***
 
 In
        2001, Ohio
        customer rates were restructured to establish separate charges for transmission,
        distribution, transition cost recovery and a generation-related component.
        When
        one of CEI's customers elects to obtain power from an alternative supplier,
        CEI
        reduces the customer's bill with a "generation shopping credit," based on
        the
        generation component (plus an incentive), and the customer receives a generation
        charge from the alternative supplier. CEI has continuing PLR responsibility
        to
        its franchise customers through December 31, 2008 unless the PUCO
        accepts
        future competitive bid results prior to the end of that period under the
        revised
        RSP.
 
 As
        part of CEI's
        transition plan, it is obligated to supply electricity to customers who do
        not
        choose an alternative supplier. CEI is also required to provide 400 MW of
        low
        cost supply (MSG) to unaffiliated alternative suppliers who serve customers
        within its service area. FES acts as an alternate supplier for a portion
        of the
        load in CEI's franchise area.
 
 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 competitive
        bid
        process. The RSP was filed by the Ohio Companies to establish generation
        service
        rates beginning January 1, 2006, in response to PUCO 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 this proceeding as well as the associated entries on rehearing. On
        September 28, 2005, the Ohio Supreme Court heard oral argument on
        the
        appeals.
 
 On
        May 27,
        2005, CEI filed an application with the PUCO to establish a GCAF rider under
        the
        RSP. The application seeks to implement recovery of increased fuel costs
        from
        2006 through 2008 applicable to CEI’s retail customers through a tariff rider to
        be implemented January 1, 2006. The application reflects projected
        increases in fuel costs in 2006 compared to 2002 baseline costs. The new
        rider,
        after adjustments made in testimony, is seeking to recover all costs above
        the
        baseline (approximately $88 million in 2006 for all of the Ohio Companies).
        Various parties including the OCC have intervened in this case and the case
        has
        been consolidated with the RCP application discussed below.
 
 On
        September 9,
        2005, CEI filed an application with the PUCO that, if approved, would supplement
        its existing RSP with an RCP. On September 27, 2005, the PUCO granted
        FirstEnergy's motion to consolidate the GCAF rider application with the RCP
        proceedings and set hearings for the consolidated cases to begin
        November 29, 2005. The RCP is designed to provide customers with more
        certain rate levels than otherwise available under the RSP during the plan
        period. Major provisions of the RCP include:





92


· Maintain
        the
        existing level of base distribution rates through April 30, 2009 for
        CEI;
 
 · Defer
        and
        capitalize 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;
 
 · Adjust
        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;
 
 · Reduce
        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
 
 · Defer
        and
        capitalize all of CEI's allowable fuel cost increases until January 1,
        2009.
 
 Under
        provisions of
        the RSP, the PUCO may require CEI to undertake, no more often than annually,
        a
        competitive bid process to secure generation for the years 2007 and 2008.
        On
        July 22, 2005, FirstEnergy filed a competitive bid process for the
        period
        beginning in 2007 that is similar to the competitive bid process approved
        by the
        PUCO for CEI in 2004, which resulted in the PUCO accepting no bids. Any
        acceptance of future competitive bid results would terminate the RSP pricing,
        with no accounting impacts to the RSP, and not until twelve months after
        the
        PUCO authorizes such termination. On September 28, 2005, the PUCO
        issued an
        Entry that essentially approved the Ohio Companies' filing but delayed the
        proposed timing of the competitive bid process by four months, calling for
        the
        auction to be held on March 21, 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 seeks recovery of these costs beginning January 1, 2006.
        At the
        time of filing the application, these costs were estimated to be approximately
        $16
        million per year; however ,
        CEI anticipates
        that this amount will increase. CEI requested that these costs be recovered
        through a rider that would be effective on January 1, 2006 and adjusted
        each July 1 thereafter. CEI reached a settlement with OCC, PUCO staff,
        Industrial Energy Users - Ohio and OPAE. The only other party in this
        proceeding, Dominion Retail, Inc., agreed not to oppose the settlement. This
        settlement, which was filed with the PUCO on July 22, 2005, provides
        for
        the rider recovery requested by CEI, with carrying charges applied in the
        subsequent year’s rider for any over or under collection while the then-current
        rider is in effect. The PUCO approved the settlement stipulation on
        August 31, 2005. The incremental Transmission and Ancillary service
        revenues expected to be recovered from January through June 2006 are
        approximately $23.9  million.
        This value
        includes the recovery of the 2005 deferred MISO expenses as described below.
        In
        May 2006, CEI will file a modification to the rider which will determine
        revenues from July 2006 through June 2007.
 
 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 CEI 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 CEI to accrue
        carrying charges on the deferred balances. An application filed with the
        PUCO to
        recover these deferred charges over a five-year period through the rider,
        beginning in 2006, was approved in a PUCO order issued on August 31,
        2005,
        approving the stipulation referred to above. The OCC, OPAE and CEI each filed
        applications for rehearing. CEI sought authority to defer the transmission
        and
        ancillary service-related costs incurred during the period October 1,
        2003
        through December 29, 2004, while both OCC and OPAE sought to have
        the PUCO
        deny deferral of all costs. On July 6, 2005, the PUCO denied CEI’s and
        OCC’s applications and, at the request of CEI, struck as untimely OPAE’s
        application. The OCC filed a notice of appeal with the Ohio Supreme Court
        on
        August 31, 2005. On
        September 30,
        2005, in accordance with appellate procedure, the PUCO filed with the Ohio
        Supreme Court the record in this case. The Companies' brief will be due thirty
        days after the OCC files its brief, which, absent any time extensions, must
        be
        filed no later than November 9, 2005.
 
 CEI
        records as
        regulatory assets costs which have been authorized by the PUCO and the FERC
        for
        recovery from
        customers in
        future periods and, without such authorization, the costs would have been
        charged to income when incurred. CEI's regulatory assets as of September
        30,
        2005 and December 2004 were $0.9 billion and $1.0 billion, respectively.
        CEI is
        deferring customer shopping incentives and interest costs as new regulatory
        assets in accordance with its transition and rate stabilization plans. These
        regulatory assets total $402 million as of September 30, 2005 and under the
        RSP,
        will be recovered through a surcharge rate equal to the RTC rate in effect
        when
        the transition costs have been fully recovered. See Note 14 “Regulatory Matters
        - Ohio” for the estimated net amortization of regulatory transition costs and
        deferred shopping incentive balances under the proposed RCP and current
        RSP.
 
 See
        Note 14 to the
        consolidated financial statements for further details and a complete discussion
        of regulatory matters in Ohio.





93




***Environmental
        Matters***
  CEI
        accrues
        environmental liabilities only when it concludes that it is probable that
        they
        have 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.
 
 FirstEnergy
        plans
        to issue a report regarding its response to air emission requirements.
        FirstEnergy expects to complete the report by December 1,
        2005.
 
 *National
        Ambient Air Quality Standards*
  In
        July 1997, the
        EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS for
        fine
        particulate matter. On March 10, 2005, the EPA finalized the "Clean
        Air
        Interstate Rule" covering a total of 28 states (including 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
        nonattainment 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 regulation 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 )
        in all cases from
        the 2003 levels. CEI's Ohio and Pennsylvania fossil-fuel generation facilities
        will be subject to the caps on SO 2 and 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 CEI 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. On March 14, 2005, the
        EPA
        finalized the “Clean Air Mercury Rule,” 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 the CAIR and the Clean Air Mercury rule
        have
        been challenged in the United States Court of Appeals for the District of
        Columbia. Future cost of compliance with these regulations may be
        substantial.
 
 *Climate
        Change*
 
 In
        December 1997,
        delegates to the United Nations' climate summit in Japan adopted an agreement,
        the Kyoto Protocol (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 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 percent through 2012. The Energy
        Policy Act of 2005 established a Committee on Climate Change Technology to
        coordinate federal climate change activities and promote the development
        and
        deployment of GHG reducing technologies.
 
 CEI
        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 KWH
        of electricity generated by CEI is lower than many regional competitors due
        to
        CEI's diversified generation sources which include low or non-CO 2 emitting gas-fired
        and nuclear generators.




94


*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, 2005,
        based on estimates of the total costs of cleanup, CEI's proportionate
        responsibility for such costs and the financial ability of other nonaffiliated
        entities to pay. Included in Other Noncurrent Liabilities are accrued
        liabilities aggregating approximately $2.3 million as of September
        30,
        2005.
 
 See
        Note 13(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 CEI's normal business operations pending against CEI and its
        subsidiaries. The other material items not otherwise discussed above are
        described below.
 
 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 concludes, 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 website (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 also is proceeding with
        the
        implementation of the recommendations regarding enhancements to regional
        reliability 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, and therefore FirstEnergy has not accrued a liability as of September
        30, 2005 for any expenditures in excess of those actually incurred through
        that
        date. FirstEnergy notes, however, that FERC or other applicable government
        agencies and reliability coordinators may take a different view as to
        recommended enhancements or may recommend additional enhancements in the
        future
        that could require additional, material expenditures. Finally, the PUCO is
        continuing to review FirstEnergy’s filing that addressed upgrades to control
        room computer hardware and software and enhancements to the training of control
        room operators, before determining the next steps, if any, in the
        proceeding.
 
 FirstEnergy
        companies also are defending six separate complaint cases before the PUCO
        relating to the August 14, 2003 power outage. Two such cases were
        originally filed in Ohio State courts but subsequently dismissed for lack
        of
        subject matter jurisdiction and further appeals were unsuccessful. In both
        such
        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. Of the four other pending PUCO complaint cases, three were filed
        by
        various insurance carriers either in their own name or as subrogees in the
        name
        of their insureds. In each such case, the carriers seek reimbursement against
        various FirstEnergy companies (and, in one case, against PJM, MISO and American
        Electric Power Co. as well) for claims they paid to their insureds allegedly
        due
        to 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 fourth
        case
        involves the claim of a non-customer seeking reimbursement for losses incurred
        when its store was burglarized on August 14, 2003. In addition to these six
        cases, the Ohio Companies were named as respondents in a regulatory proceeding
        that was initiated at the PUCO in response to complaints alleging failure
        to
        provide reasonable and adequate service stemming primarily from the
        August 14, 2003 power
        outages. No
        estimate of potential liability has been undertaken for any of these cases.




95


One
        complaint was
        filed on August 25, 2004 against FirstEnergy in the New York State Supreme
        Court. In this case, several plaintiffs in the New York City metropolitan
        area
        allege that they suffered damages as a result of the August 14, 2003
        power
        outages. None of the plaintiffs are customers of any FirstEnergy affiliate.
        FirstEnergy's motion to dismiss the case was granted on September 26,
        2005.
        Additionally, FirstEnergy Corp. was named in a complaint filed in Michigan
        State
        Court by an individual who is not a customer of any FirstEnergy company.
        A
        responsive pleading to this matter is not due until on or about December
        1,
        2005. No estimate of potential liability has been undertaken in this matter.
 
 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.
 
 FENOC
        received a
        subpoena in late 2003 from a grand jury sitting in the United States District
        Court for the Northern District of Ohio, Eastern Division requesting the
        production of certain documents and records relating to the inspection and
        maintenance of the reactor vessel head at the Davis-Besse Nuclear Power Station,
        in which CEI has a 51.38% interest. On December 10, 2004, FirstEnergy
        received a letter from the United States Attorney's Office stating that FENOC
        is
        a target of the federal grand jury investigation into alleged false statements
        made to the NRC in the Fall of 2001 in response to NRC Bulletin 2001-01.
        The
        letter also said that the designation of FENOC as a target indicates that,
        in
        the view of the prosecutors assigned to the matter, it is likely that federal
        charges will be returned against FENOC by the grand jury. On February 10,
        2005, FENOC received an additional subpoena for documents related to root
        cause
        reports regarding reactor head degradation and the assessment of reactor
        head
        management issues at Davis-Besse. On May 11, 2005, FENOC received
        a
        subpoena for documents related to outside meetings attended by Davis-Besse
        personnel on corrosion and cracking of control rod drive mechanisms and
        additional root cause evaluations.
 
 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 described above.
        CEI accrued $1.0 million for a potential fine prior to 2005 and accrued the
        remaining liability for its share of the proposed fine of $1.8 million 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.
 
 If
        it were
        ultimately determined that FirstEnergy or its subsidiaries have legal liability
        based on the events surrounding Davis-Besse, it could have a material adverse
        effect on FirstEnergy's or its subsidiaries' financial condition, results
        of
        operations and cash flows.
 
 Effective
        July 1, 2005 the NRC oversight panel for Davis-Besse was terminated
        and
        Davis-Besse returned to the standard NRC reactor oversight process. At that
        time, NRC inspections were augmented to include inspections to support the
        NRC's
        Confirmatory Order dated March 8, 2004 that was issued at the time
        of
        startup and to address an NRC White Finding related to emergency
        sirens.
 
 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 effective corrective action. FENOC operates the Perry Nuclear Power Plant,
        in which CEI has a 44.85% interest (however, see Note 17 regarding FirstEnergy’s
        pending intra-system generation asset transfers, which include owned portions
        of
        the 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.


96


On
          May 26,
          2005, the NRC held a public meeting to discuss its oversight of the Perry
          Plant.
          While the NRC stated that the plant continued to operate safely, the NRC
          also
          stated that the overall performance had not substantially improved since
          the
          heightened inspection was initiated. The NRC reiterated this conclusion
          in its
          mid-year assessment letter dated August 30, 2005. On September 28,
          2005, the NRC sent a CAL to FENOC describing commitments that FENOC had
          made to
          improve the performance of Perry 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. 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. As a result, these
          matters could have a material adverse effect on FirstEnergy's or its
          subsidiaries' financial condition, results of operations and cash
          flows.
 
 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 CEI, 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 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. 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. An
          adverse ruling
          could negatively affect full recovery of transition charges by CEI. 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.
          It is unknown when the PUCO will rule on this case.
 
 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 13(C) to
          the consolidated financial statements for further details and a complete
          discussion of other legal proceedings.
 
 **New
          Accounting Standards and Interpretations**
 
 *EITF
          Issue
          04-13, "Accounting for Purchases and Sales of Inventory with the Same
          Counterparty"*
  In
          September 2005,
          the EITF reached a final consensus on Issue 04-13 concluding that two or
          more
          legally separate exchange transactions with the same counterparty should
          be
          combined and considered as a single arrangement for purposes of applying
          APB 29,
          when the transactions were entered into "in contemplation" of one another.
          If
          two transactions are combined and considered a single arrangement, the
          EITF
          reached a consensus that an exchange of inventory should be accounted for
          at
          fair value. Although electric power is not capable of being held in inventory,
          there is no substantive conceptual distinction between exchanges involving
          power
          and other storable inventory. Therefore, CEI will adopt this EITF effective
          for
          new arrangements entered into, or modifications or renewals of existing
          arrangements, in interim or annual periods beginning after March 15, 2006.
 
 *EITF
                    Issue No. 05-6, "Determining the Amortization Period for Leasehold
                    Improvements Purchased after Lease Inception or Acquired in a
                    Business
                    Combination"*
  In
          June 2005, the
          EITF reached a consensus on the application guidance for Issue 05-6. EITF
          05-6
          addresses the amortization period for leasehold improvements that were
          either
          acquired in a business combination or placed in service significantly after
          and
          not contemplated at or near the beginning of the initial lease term. For
          leasehold improvements acquired in a business combination, the amortization
          period is the shorter of the useful life of the assets or a term that includes
          required lease periods and renewals that are deemed to be reasonably assured
          at
          the date of acquisition. Leasehold improvements that are placed in service
          significantly after and not contemplated at or near the beginning of the
          lease
          term should be amortized over the shorter of the useful life of the assets
          or a
          term that includes required lease periods and renewals that are deemed
          to be
          reasonably assured at the date the leasehold improvements are purchased.
          This
          EITF was effective July 1, 2005 and is consistent with CEI’s current
          accounting.
  
 97





*FIN
        47,
“Accounting for Conditional Asset Retirement Obligations - an interpretation
        of
        FASB Statement No. 143”*
 
 On
        March 30,
        2005, the FASB issued FIN 47 to clarify the scope and timing of liability
        recognition for conditional asset retirement obligations. Under this
        interpretation, companies are required to recognize a liability for the fair
        value of an asset retirement obligation that is conditional on a future event,
        if the fair value of the liability can be reasonably estimated. In instances
        where there is insufficient information to estimate the liability, the
        obligation is to be recognized in the first period in which sufficient
        information becomes available to estimate its fair value. If the fair value
        cannot be reasonably estimated, that fact and the reasons why must be disclosed.
        This Interpretation is effective for CEI in the fourth quarter of 2005. CEI
        is
        currently evaluating the effect this Interpretation will have on its financial
        statements.
 
 *SFAS
                  154
                  - “Accounting Changes and Error Corrections - a replacement of APB
                  Opinion
                  No. 20 and FASB Statement No.
                  3”*
 
 In
        May 2005, the
        FASB issued SFAS 154 to change the requirements for accounting and reporting
        a
        change in accounting principle. It applies to all voluntary changes in
        accounting principle and to changes required by an accounting pronouncement
        when
        that pronouncement does not include specific transition provisions. This
        Statement requires retrospective application to prior periods’ financial
        statements of changes in accounting principle, unless it is impracticable
        to
        determine either the period-specific effects or the cumulative effect of
        the
        change. In those instances, this Statement requires that the new accounting
        principle be applied to the balances of assets and liabilities as of the
        beginning of the earliest period for which retrospective application is
        practicable and that a corresponding adjustment be made to the opening balance
        of retained earnings (or other appropriate components of equity or net assets
        in
        the statement of financial position) for that period rather than being reported
        in the Consolidated Statements of Income. This Statement also requires that
        a
        change in depreciation, amortization, or depletion method for long-lived,
        nonfinancial assets be accounted for as a change in accounting estimate affected
        by a change in accounting principle. The provisions of this Statement are
        effective for accounting changes and corrections of errors made in fiscal
        years
        beginning after December 15, 2005. CEI will adopt this Statement effective
        January 1, 2006.
 
 *SFAS
                  153,
                  “Exchanges of Nonmonetary Assets - an amendment of APB Opinion No.
                  29”*
 
 In
        December 2004,
        the FASB issued SFAS 153 amending APB 29, which was based on the principle
        that
        nonmonetary assets should be measured based on the fair value of the assets
        exchanged. The guidance in APB 29 included certain exceptions to that principle.
        SFAS 153 eliminates the exception from fair value measurement for nonmonetary
        exchanges of similar productive assets and replaces it with an exception
        for
        exchanges that do not have commercial substance. This Statement specifies
        that a
        nonmonetary exchange has commercial substance if the future cash flows of
        the
        entity are expected to change significantly as a result of the exchange.
        The
        provisions of this Statement are effective January 1, 2006 for CEI.
        This
        FSP is not expected to have a material impact on CEI’s financial
        statements.
 
 *SFAS
        151,
“Inventory Costs - an amendment of ARB No. 43, Chapter 4”*
 
 In
        November 2004,
        the FASB issued SFAS 151 to clarify the accounting for abnormal amounts of
        idle
        facility expense, freight, handling costs and wasted material (spoilage).
        Previous guidance stated that in some circumstances these costs may be “so
        abnormal” that they would require treatment as current period costs. SFAS 151
        requires abnormal amounts for these items to always be recorded as current
        period costs. In addition, this Statement requires that allocation of fixed
        production overheads to the cost of conversion be based on the normal capacity
        of the production facilities. The provisions of this statement are effective
        for
        inventory costs incurred by CEI beginning January 1, 2006. CEI is
        currently
        evaluating this Standard and does not expect it to have a material impact
        on its
        financial statements.
 
 *FSP
        FAS 115-1,
        "The Meaning of Other-Than-Temporary Impairment and its Application to Certain
        Investments"*
 
 In
        September 2005,
        the FASB finalized and renamed EITF 03-1 and 03-1-a to FSP FAS 115-1. FSP
        FAS
        115-1 will (1) supersede Issue 03-1 and EITF topic No. D-44, "Recognition
        of
        Other Than Temporary Impairment upon the Planned Sale of a Security Whose
        Cost
        Exceeds Fair Value," (2) clarify that an investor should recognize an impairment
        loss no later than when the impairment is deemed other than temporary, even
        if a
        decision to sell has not been made, and (3) be effective for
        other-than-temporary impairment and analyses conducted in periods beginning
        after September 15, 2005. The FASB expects to issue this FSP in the
        fourth
        quarter of 2005, which would require prospective application with an effective
        date for reporting periods beginning after December 15, 2005. CEI is currently
        evaluating this FSP and any impact on its investments.




98




**THE
                      TOLEDO EDISON COMPANY****CONSOLIDATED
                      STATEMENTS OF INCOME AND COMPREHENSIVE INCOME****(Unaudited)****Three
                      Months Ended**
                  
                  **Nine
                      Months Ended****September
                      30,**
                  
                  **September
                      30,****2005**
                  
                  **2004**
                  
                  **2005**
                  
                  **2004*****(In
                      thousands)*****STATEMENTS
                      OF INCOME****OPERATING
                      REVENUES**
                  
                  $
                  286,960
                  
                  $
                  276,342
                  
                  $
                  787,824
                  
                  $
                  755,106**OPERATING
                      EXPENSES AND TAXES:**Fuel
                  
                  
                  16,501
                  
                  
                  13,908
                  
                  
                  43,474
                  
                  
                  37,195Purchased
                      power
                  
                  
                  73,144
                  
                  
                  79,774
                  
                  
                  225,600
                  
                  
                  236,869Nuclear
                      operating costs
                  
                  
                  39,207
                  
                  
                  43,827
                  
                  
                  145,059
                  
                  
                  122,685Other
                      operating costs
                  
                  
                  48,164
                  
                  
                  43,865
                  
                  
                  123,823
                  
                  
                  121,228Provision
                      for
                      depreciation
                  
                  
                  18,835
                  
                  
                  14,588
                  
                  
                  48,724
                  
                  
                  43,021Amortization
                      of regulatory assets
                  
                  
                  39,576
                  
                  
                  41,037
                  
                  
                  107,672
                  
                  
                  102,065Deferral
                      of
                      new regulatory assets
                  
                  
                  (19,379
                  )
                  
                  (12,442
                  )
                  
                  (41,473
                  )
                  
                  (29,664
                  )General
                      taxes
                  
                  
                  14,159
                  
                  
                  14,924
                  
                  
                  41,960
                  
                  
                  41,252Income
                      taxes
                  
                  
                  20,311
                  
                  
                  11,963
                  
                  
                  44,160
                  
                  
                  18,465Total
                      operating expenses and taxes
                  
                  
                  250,518
                  
                  
                  251,444
                  
                  
                  738,999
                  
                  
                  693,116**OPERATING
                      INCOME**
                  
                  
                  36,442
                  
                  
                  24,898
                  
                  
                  48,825
                  
                  
                  61,990**OTHER
                      INCOME (net of income taxes)**
                  
                  
                  12,283
                  
                  
                  4,172
                  
                  
                  18,173
                  
                  
                  14,724**NET
                      INTEREST CHARGES:**Interest
                      on
                      long-term debt
                  
                  
                  3,912
                  
                  
                  4,015
                  
                  
                  12,655
                  
                  
                  23,057Allowance
                      for
                      borrowed funds used during construction
                  
                  
                  (372
                  )
                  
                  (741
                  )
                  
                  (117
                  )
                  
                  (2,843
                  )Other
                      interest expense
                  
                  
                  2,958
                  
                  
                  1,350
                  
                  
                  4,192
                  
                  
                  2,945Net
                      interest
                      charges
                  
                  
                  6,498
                  
                  
                  4,624
                  
                  
                  16,730
                  
                  
                  23,159**NET
                      INCOME**
                  
                  
                  42,227
                  
                  
                  24,446
                  
                  
                  50,268
                  
                  
                  53,555**PREFERRED
                      STOCK DIVIDEND REQUIREMENTS**
                  
                  
                  1,687
                  
                  
                  2,211
                  
                  
                  6,109
                  
                  
                  6,633**EARNINGS
                      ON COMMON STOCK**
                  
                  $
                  40,540
                  
                  $
                  22,235
                  
                  $
                  44,159
                  
                  $
                  46,922**STATEMENTS
                      OF COMPREHENSIVE INCOME****NET
                      INCOME**
                  
                  $
                  42,227
                  
                  $
                  24,446
                  
                  $
                  50,268
                  
                  $
                  53,555**OTHER
                      COMPREHENSIVE INCOME (LOSS):**Unrealized
                      gain (loss) on available for sale securities
                  
                  
                  (4,511
                  )
                  
                  913
                  
                  
                  (6,695
                  )
                  
                  (379
                  )Income
                      tax
                      expense (benefit) related to other comprehensive income
                  
                  
                  (1,743
                  )
                  
                  375
                  
                  
                  (2,534
                  )
                  
                  (155
                  )Other
                      comprehensive income (loss), net of tax
                  
                  
                  (2,768
                  )
                  
                  538
                  
                  
                  (4,161
                  )
                  
                  (224
                  )**TOTAL
                      COMPREHENSIVE INCOME**
                  
                  $
                  39,459
                  
                  $
                  24,984
                  
                  $
                  46,107
                  
                  $
                  53,331The
                      preceding
                      Notes to Consolidated Financial Statements as they relate to
                      The Toledo
                      Edison Company are an integral part of  these
                      statements.
   99
  **THE
                      TOLEDO EDISON COMPANY****CONSOLIDATED
                      BALANCE SHEETS****(Unaudited)****September
                      30,**
                  
                  **December
                      31,****2005**
                  
                  **2004*****(In
                      thousands)*****ASSETS****UTILITY
                      PLANT:**In
                      service
                  
                  $
                  1,906,941
                  
                  $
                  1,856,478Less
                      -
                      Accumulated provision for depreciation
                  
                  
                  820,562
                  
                  
                  778,8641,086,379
                  
                  
                  1,077,614Construction
                      work in progress -Electric
                      plant
                  
                  
                  55,376
                  
                  
                  58,535Nuclear
                      fuel
                  
                  
                  7,370
                  
                  
                  15,99862,746
                  
                  
                  74,5331,149,125
                  
                  
                  1,152,147**OTHER
                      PROPERTY AND INVESTMENTS:**Investment
                      in
                      lessor notes
                  
                  
                  178,765
                  
                  
                  190,692Nuclear
                      plant
                      decommissioning trusts
                  
                  
                  335,553
                  
                  
                  297,803Long-term
                      notes receivable from associated companies
                  
                  
                  39,964
                  
                  
                  39,975Other
                  
                  
                  1,741
                  
                  
                  2,031556,023
                  
                  
                  530,501**CURRENT
                      ASSETS:**Cash
                      and cash
                      equivalents
                  
                  
                  15
                  
                  
                  15Receivables
                      -Customers
                      (less accumulated provision of $2,000 foruncollectible
                      accounts in 2004)
                  
                  
                  2,412
                  
                  
                  4,858Associated
                      companies
                  
                  
                  10,168
                  
                  
                  36,570Other
                  
                  
                  8,658
                  
                  
                  3,842Notes
                      receivable from associated companies
                  
                  
                  52,639
                  
                  
                  135,683Materials
                      and
                      supplies, at average cost
                  
                  
                  42,404
                  
                  
                  40,280Prepayments
                      and other
                  
                  
                  1,712
                  
                  
                  1,150118,008
                  
                  
                  222,398**DEFERRED
                      CHARGES:**Goodwill
                  
                  
                  501,022
                  
                  
                  504,522Regulatory
                      assets
                  
                  
                  309,835
                  
                  
                  374,814Property
                      taxes
                  
                  
                  24,100
                  
                  
                  24,100Other
                  
                  
                  26,520
                  
                  
                  25,424861,477
                  
                  
                  928,860$
                  2,684,633
                  
                  $
                  2,833,906**CAPITALIZATION
                      AND LIABILITIES****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
                  
                  
                  428,572
                  
                  
                  428,559Accumulated
                      other comprehensive income
                  
                  
                  15,878
                  
                  
                  20,039Retained
                      earnings
                  
                  
                  225,218
                  
                  
                  191,059Total
                      common
                      stockholder's equity
                  
                  
                  865,338
                  
                  
                  835,327Preferred
                      stock
                  
                  
                  96,000
                  
                  
                  126,000Long-term
                      debt
                  
                  
                  296,373
                  
                  
                  300,2991,257,711
                  
                  
                  1,261,626**CURRENT
                      LIABILITIES:**Currently
                      payable long-term debt
                  
                  
                  53,650
                  
                  
                  90,950Accounts
                      payable -Associated
                      companies
                  
                  
                  28,456
                  
                  
                  110,047Other
                  
                  
                  3,252
                  
                  
                  2,247Notes
                      payable
                      to associated companies
                  
                  
                  378,190
                  
                  
                  429,517Accrued
                      taxes
                  
                  
                  72,214
                  
                  
                  46,957Lease
                      market
                      valuation liability
                  
                  
                  24,600
                  
                  
                  24,600Other
                  
                  
                  28,735
                  
                  
                  53,055589,097
                  
                  
                  757,373**NONCURRENT
                      LIABILITIES:**Accumulated
                      deferred income taxes
                  
                  
                  222,985
                  
                  
                  221,950Accumulated
                      deferred investment tax credits
                  
                  
                  24,697
                  
                  
                  25,102Lease
                      market
                      valuation liability
                  
                  
                  249,550
                  
                  
                  268,000Retirement
                      benefits
                  
                  
                  42,998
                  
                  
                  39,227Asset
                      retirement obligation
                  
                  
                  200,078
                  
                  
                  194,315Other
                  
                  
                  97,517
                  
                  
                  66,313837,825
                  
                  
                  814,907**COMMITMENTS
                      AND CONTINGENCIES (Note 13)**$
                  2,684,633
                  
                  $
                  2,833,906The
                      preceding
                      Notes to Consolidated Financial Statements as they relate to
                      The Toledo
                      Edison Company are an integral part of these blance sheets.
   100
 **THE
                      TOLEDO EDISON COMPANY****CONSOLIDATED
                      STATEMENTS OF CASH FLOWS****(Unaudited)****Three
                      Months Ended**
                  
                  **Nine
                      Months Ended****September
                      30,**
                  
                  **September
                      30,****2005**
                  
                  **2004**
                  
                  **2005**
                  
                  **2004*****(In
                      thousands)*****CASH
                      FLOWS FROM OPERATING ACTIVITIES:**Net
                      income
                  
                  $
                  42,227
                  
                  $
                  24,446
                  
                  $
                  50,268
                  
                  $
                  53,555Adjustments
                      to reconcile net income to net cash fromoperating
                      activities -Provision
                      for
                      depreciation
                  
                  
                  18,835
                  
                  
                  14,588
                  
                  
                  48,724
                  
                  
                  43,021Amortization
                      of regulatory assets
                  
                  
                  39,576
                  
                  
                  41,037
                  
                  
                  107,672
                  
                  
                  102,065Deferral
                      of
                      new regulatory assets
                  
                  
                  (19,379
                  )
                  
                  (12,442
                  )
                  
                  (41,473
                  )
                  
                  (29,664
                  )Nuclear
                      fuel
                      and capital lease amortization
                  
                  
                  5,682
                  
                  
                  7,058
                  
                  
                  13,816
                  
                  
                  17,596Amortization
                      of electric service obligation
                  
                  
                  (1,910
                  )
                  
                  -
                  
                  
                  (3,301
                  )
                  
                  -Deferred
                      rents and lease market valuation liability
                  
                  
                  10,310
                  
                  
                  9,689
                  
                  
                  (34,156
                  )
                  
                  (26,585
                  )Deferred
                      income taxes and investment tax credits, net
                  
                  
                  (12,798
                  )
                  
                  (4,608
                  )
                  
                  (4,605
                  )
                  
                  (9,290
                  )Accrued
                      retirement benefit obligations
                  
                  
                  1,534
                  
                  
                  1,324
                  
                  
                  3,771
                  
                  
                  4,733Accrued
                      compensation, net
                  
                  
                  404
                  
                  
                  516
                  
                  
                  (333
                  )
                  
                  1,477Pension
                      trust
                      contribution
                  
                  
                  -
                  
                  
                  (12,572
                  )
                  
                  -
                  
                  
                  (12,572
                  )Decrease
                      (increase) in operating assets -Receivables
                  
                  
                  3,423
                  
                  
                  69,908
                  
                  
                  15,962
                  
                  
                  95,383Materials
                      and
                      supplies
                  
                  
                  3,788
                  
                  
                  (725
                  )
                  
                  (2,124
                  )
                  
                  (4,376
                  )Prepayments
                      and other current assets
                  
                  
                  (970
                  )
                  
                  677
                  
                  
                  (562
                  )
                  
                  5,971Increase
                      (decrease) in operating liabilities -Accounts
                      payable
                  
                  
                  (6,215
                  )
                  
                  6,202
                  
                  
                  (80,586
                  )
                  
                  (9,568
                  )Accrued
                      taxes
                  
                  
                  14,748
                  
                  
                  (3,508
                  )
                  
                  25,257
                  
                  
                  227Accrued
                      interest
                  
                  
                  (369
                  )
                  
                  (7,169
                  )
                  
                  (565
                  )
                  
                  (7,540
                  )Prepayment
                      for electric service -- education programs
                  
                  
                  -
                  
                  
                  -
                  
                  
                  37,954
                  
                  
                  -Other
                  
                  
                  (14,392
                  )
                  
                  (10,020
                  )
                  
                  (22,999
                  )
                  
                  (9,679
                  )Net
                      cash
                      provided from operating activities
                  
                  
                  84,494
                  
                  
                  124,401
                  
                  
                  112,720
                  
                  
                  214,754**CASH
                      FLOWS FROM FINANCING ACTIVITIES:**New
                      Financing
                      -Long-term
                      debt
                  
                  
                  -
                  
                  
                  30,500
                  
                  
                  45,000
                  
                  
                  103,500Short-term
                      borrowings, net
                  
                  
                  45,054
                  
                  
                  146,370
                  
                  
                  -
                  
                  
                  29,310Redemptions
                      and Repayments -Preferred
                      stock
                  
                  
                  (30,000
                  )
                  
                  -
                  
                  
                  (30,000
                  )
                  
                  -Long-term
                      debt
                  
                  
                  (36,821
                  )
                  
                  (246,591
                  )
                  
                  (83,754
                  )
                  
                  (261,591
                  )Short-term
                      borrowings, net
                  
                  
                  -
                  
                  
                  -
                  
                  
                  (51,327
                  )
                  
                  -Dividend
                      Payments -Common
                      stock
                  
                  
                  -
                  
                  
                  -
                  
                  
                  (10,000
                  )
                  
                  -Preferred
                      stock
                  
                  
                  (1,687
                  )
                  
                  (2,211
                  )
                  
                  (6,109
                  )
                  
                  (6,633
                  )Net
                      cash used
                      for financing activities
                  
                  
                  (23,454
                  )
                  
                  (71,932
                  )
                  
                  (136,190
                  )
                  
                  (135,414
                  )**CASH
                      FLOWS FROM INVESTING ACTIVITIES:**Property
                      additions
                  
                  
                  (17,951
                  )
                  
                  (16,950
                  )
                  
                  (50,119
                  )
                  
                  (36,377
                  )Loan
                      repayments from (loans to) associated companies, net
                  
                  
                  (36,490
                  )
                  
                  (20,389
                  )
                  
                  83,055
                  
                  
                  (21,046
                  )Investments
                      in lessor notes
                  
                  
                  32
                  
                  
                  -
                  
                  
                  11,927
                  
                  
                  10,280Contributions
                      to nuclear decommissioning trusts
                  
                  
                  (7,135
                  )
                  
                  (7,135
                  )
                  
                  (21,406
                  )
                  
                  (21,406
                  )Other
                  
                  
                  504
                  
                  
                  (7,995
                  )
                  
                  13
                  
                  
                  (13,013
                  )Net
                      cash
                      provided from (used for) investing activities
                  
                  
                  (61,040
                  )
                  
                  (52,469
                  )
                  
                  23,470
                  
                  
                  (81,562
                  )Net
                      change in
                      cash and cash equivalents
                  
                  
                  -
                  
                  
                  -
                  
                  
                  -
                  
                  
                  (2,222
                  )Cash
                      and cash
                      equivalents at beginning of period
                  
                  
                  15
                  
                  
                  15
                  
                  
                  15
                  
                  
                  2,237Cash
                      and cash
                      equivalents at end of period
                  
                  $
                  15
                  
                  $
                  15
                  
                  $
                  15
                  
                  $
                  15The
                      preceding
                      Notes to Consolidated Financial Statements as they relate to
                      The Toledo
                      Edison Company are an integral part of these statements.
    101
 ***Report
          of Independent Registered Public Accounting Firm***
 
 
 
 
 
 
 
 
 
 To
          the Stockholders
          and Board of
 Directors
          of The
          Toledo Edison Company:
 
 We
          have reviewed
          the accompanying consolidated balance sheet of The Toledo Edison Company
          and its
          subsidiary as of September 30, 2005, and the related consolidated
          statements of income and comprehensive income and cash flows for each of
          the
          three-month and nine-month periods ended September 30, 2005 and
          2004. 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
          previously
          audited, in accordance with the standards of the Public Company Accounting
          Oversight Board (United States), the consolidated balance sheet as of
          December 31, 2004, and the related consolidated statements of income,
          capitalization, common stockholder’s 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,
          2004 and the effectiveness of the Company’s internal control over financial
          reporting as of December 31, 2004; 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) 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 March 7, 2005, 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 information as of December 31,
          2004, is fairly stated in all material respects in relation to the consolidated
          balance sheet from which it has been derived.
 
 
 
 
 PricewaterhouseCoopers
          LLP
 Cleveland,
          Ohio
 November
          1,
          2005
 102
 **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 provides power directly to some alternative energy suppliers
          under TE’s transition plan. TE has unbundled the price of electricity into its
          component elements - including generation, transmission, distribution and
          transition charges. TE’s power supply requirements are provided by FES - an
          affiliated company.
 
 **Results
          of Operations**
 
 Earnings
          on common
          stock in the third quarter of 2005 increased to $41 million from $22 million
          in
          the third quarter of 2004. The increase in earnings resulted primarily
          from
          higher operating revenues and other income, partially offset by increased
          financing costs. Earnings
          on common
          stock in the first
          nine
          m onths
          of 2005 decreased to $ 4 4
          million from
          $ 47 million in the
          first nine months of 2004. The decrease in earnings resulted primarily
          from
          higher nuclear operating costs and a one-time income tax charge, partially
          offset by higher operating revenues and lower financing costs.
 
 Operating
          revenues
          increased by $11 million, or 3.8%, in the third quarter of 2005 compared
          to the
          third quarter of 2004. Higher revenues in the third quarter of 2005 resulted
          from increased retail generation revenues of $13 million and distribution
          revenues of $2 million, partially offset by a decrease in wholesales sales
          (primarily to FES) of $4 million and an increase in shopping incentive
          credits
          of $1 million. Retail generation revenues increased as a result of increased
          KWH
          sales (residential - $1 million, commercial - $1 million and industrial
          - $11
          million). Higher residential and commercial revenues reflected increased
          KWH
          sales (8.0% and 9.2%, respectively) and higher unit prices. KWH sales to
          residential and commercial customers increased primarily due to warmer
          weather
          which increased air-conditioning loads. Additionally, generation services
          provided to commercial customers by alternative suppliers as a percent
          of total
          commercial sales delivered in TE’s service area decreased by 2.1 percentage
          points compared with the third quarter of 2004. Industrial revenues increased
          as
          a result of higher unit prices and a 4.2% increase in KWH sales.
 
 Revenues
          from
          distribution throughput increased by $2 million in the third quarter of
          2005
          from the corresponding quarter of 2004. The increase was due to higher
          residential and commercial revenues ($8 million and $0.2 million,
          respectively), partially offset by a decrease in industrial revenues ($7
          million). The impact of higher residential and commercial KWH sales contributed
          to the increase; lower industrial unit prices more than offset an increase
          in
          KWH sales to industrial customers.
 
 Operating
          revenues
          increased by $33 million, or 4.3%, in the first nine months of 2005 compared
          to
          the same period of 2004. The higher revenues resulted from increased retail
          generation revenues of $35 million and wholesales sales of $2 million,
          partially
          offset by an increase in shopping incentive credits of $3 million. Retail
          generation revenues increased as a result of higher KWH sales (residential
          - $2
          million, commercial - $4 million, industrial - $29 million). Higher residential
          and commercial revenues reflected increased KWH sales (6.9% and 12.2%,
          respectively) and higher unit prices. Residential and commercial sales
          volumes
          increased primarily due to warmer weather. The increase in commercial revenues
          also reflects a reduction by 2.5 percentage points in customer shopping
          compared
          with the same period of 2004. Industrial revenues increased as a result
          of
          higher unit prices and a 0.6% increase in KWH sales.
 
 Revenues
          from
          distribution throughput decreased by $0.4 million in the first nine months
          of
          2005 from the same period in 2004. The decrease was due to lower industrial
          revenues ($22 million), partially offset by increases in residential and
          commercial revenues ($15 million and $6 million, respectively). The impact
          from
          lower industrial unit prices more than offset the higher KWH sales in all
          customer classes.
 
 Under
          the Ohio
          transition plan, TE provides incentives to customers to encourage switching
          to
          alternative energy providers. TE’s revenues were reduced by $1 million from
          additional credits in the third quarter and $3 million in the first nine
          months
          of 2005 compared with the same periods of 2004. These revenue reductions
          are
          deferred for future recovery under TE’s transition plan and do not affect
          current period earnings (see Regulatory Matters below).
 103
 Changes
          in KWH
          sales by customer class in the three months and nine months ended
          September 30, 2005 from the corresponding periods of 2004, are summarized
          in the following table:
 
 **Three**
              
              **Nine****Changes
                  in KWH Sales**
              
              **Months**
              
              **Months****Increase
                  (Decrease)**Electric
                  Generation:Retail
              
              
              6.0
              %
              
              3.9
              %Wholesale
              
              
              3.5
              %
              
              3.4
              %**Total
                  Electric Generation Sales**
              
              
              **4.6**
              **%**
              
              **3.7**
              **%**Distribution
                  Deliveries:Residential
              
              
              16.7
              %
              
              12.0
              %Commercial
              
              
              4.7
              %
              
              6.8
              %Industrial
              
              
              4.8
              %
              
              1.2
              %**Total
                  Distribution Deliveries**
              
              
              **7.7**
              **%**
              
              **5.3**
              **%**
 
 *Operating
          Expenses and Taxes*
 
 Total
          operating
          expenses and taxes decreased $1 million in the third quarter and increased
          $46
          million in the first nine months of 2005 from the same periods in 2004.
          The
          following table presents changes from the prior year by expense category.
  **Three**
              
              **Nine****Operating
                  Expenses and Taxes - Changes**
              
              **Months**
              
              **Months****Increase
                  (Decrease)**
              
              ***(In
                  millions)***Fuel
                  costs
              
              $
              3
              
              $
              6Purchased
                  power costs
              
              
              (7
              )
              
              (11
              )Nuclear
                  operating costs
              
              
              (4
              )
              
              22Other
                  operating costs
              
              
              4
              
              
              3Provision
                  for
                  depreciation
              
              
              4
              
              
              6Amortization
                  of regulatory assets
              
              
              (1
              )
              
              6Deferral
                  of
                  new regulatory assets
              
              
              (7
              )
              
              (12
              )General
                  taxes
              
              
              (1
              )
              
              1Income
                  taxes
              
              
              8
              
              
              25**Net
                  increase (decrease) in operating expenses and
                  taxes**
              
              $
              (1
              )
              $
              46
 
 Higher
          fuel costs
          in the third quarter and first nine months of 2005, compared with the same
          periods of 2004, resulted primarily from increased fossil-fired generation
          from
          the Mansfield Plant, up 5.7% and 7.1% during the respective periods. Purchased
          power costs decreased in both periods due to lower unit costs and reduced
          KWH
          purchases. Nuclear operating costs decreased in the third quarter of 2005
          primarily from lower employee benefit costs and operating expenses for
          the
          nuclear generating units. Nuclear operating costs increased in the nine-month
          period due to a scheduled refueling outage (including an unplanned extension)
          at
          the Perry Plant, a mid-cycle inspection outage at the Davis-Besse Plant
          during
          the first quarter of 2005, and the Beaver Valley Unit 2 refueling outage
          in the
          second quarter of 2005, compared to no scheduled outages in the first nine
          months of 2004. Other operating costs increased in both periods of 2005
          compared
          to the same periods of 2004 primarily because of MISO Day 2 expenses that
          began
          on April 1, 2005, partially offset by lower Beaver Valley Unit 2
          letter of
          credit fees, insurance settlements and lower employee benefits
          costs.
 
 Depreciation
          charges increased by $4 million in the third quarter and $6 million in
          first
          nine months of 2005 compared to the same periods of 2004 primarily due
          to
          property additions and reduced amortization periods for expenditures on
          leased
          generating plants to conform to the lease terms. These increases were partially
          offset by the effect of revised service life assumptions for fossil generating
          plants (See Note 3). Regulatory asset amortization increased in the first
          nine
          months of 2005 due to the increased amortization of transition costs being
          recovered under the RSP. Deferrals of new regulatory assets increased in
          the
          third quarter and first nine months of 2005 compared to the same periods
          of
          2004, primarily due to higher shopping incentives and related interest
          ($2
          million and $5 million, respectively) and the deferral of the PUCO-approved
          MISO
          administrative expenses and related interest ($5 million and $6 million,
          respectively).
 
 On
          June 30,
          2005, the State of Ohio enacted new tax legislation that created a new
          CAT tax,
          which is based on qualifying “taxable gross receipts” and will not consider any
          expenses or costs incurred to generate such receipts, except for items
          such as
          cash discounts, returns and allowances, and bad debts. The CAT tax is effective
          July 1, 2005, and replaces the Ohio income-based franchise tax and
          the Ohio
          personal property tax. The CAT tax is phased-in while the current income-based
          franchise tax is phased-out over a five-year period at a rate of 20% annually,
          beginning with the year ended 2005, and personal property tax is phased-out
          over
          a four-year period at a rate of approximately 25%, annually beginning with
          the
          year ended 2005. For example, during the phase-out period the Ohio income-based
          franchise tax will be computed consistently with the prior tax law, except
          that
          the tax liability as computed will be multiplied by 4/5 in 2005; 3/5 in
          2006;
          2/5 in 2007 and 1/5 in 2008, therefore eliminating the current income-based
          franchise tax over a five-year period. As a result of the new tax structure,
          all
          net deferred tax benefits that are not expected to reverse during the five-year
          phase-in period were written-off as of June 30, 2005. The impact
          on income
          taxes associated with the required adjustment to net deferred taxes for
          the nine
          months ended September 30, 2005 was additional tax expense of $17.5
          million, which was partially offset by the phase-out of the Ohio income
          tax
          which reduced income taxes by $0.7 million in the third quarter of 2005
          and $1.2
          million for the nine months ended September 30, 2005. See Note 12
          to the
          consolidated financial statements.
  104
 *Other
          Income*
 
 Other
          income
          increased by $8 million in the third quarter of 2005 and $3 million in
          the first
          nine months of 2005 compared with the same periods of 2004, primarily due
          to
          higher nuclear decommissioning trust realized gains, partially offset by
          lower
          interest income earned on associated company notes receivable that were
          repaid
          in May 2005. Additionally, the recognition of a $1.6 million NRC fine related
          to
          the Davis-Besse Plant (see Outlook - Other Legal Proceedings) during the
          first
          quarter of 2005 partially offset the increase in other income during the
          first
          nine months of 2005.
 
 *Net
          Interest
          Charges*
 
 Net
          interest
          charges increased by $2 million in the third quarter of 2005 compared with
          the
          same period in 2004, primarily related to higher interest rates charged
          for
          money pool borrowings from associated companies in 2005. The average interest
          rate for borrowings in the third quarter of 2005 was 3.50% versus 1.28%
          in the
          same period in 2004. However, net interest charges decreased by $6 million
          in
          the first nine months of 2005 compared with the same period of 2004, reflecting
          redemptions and refinancings since October 1, 2004.
 
 **Capital
          Resources and Liquidity**
 
 TE’s
          cash
          requirements for the remainder of 2005 for operating expenses and construction
          expenditures are expected to be met without increasing its net debt and
          preferred stock outstanding. Thereafter, TE expects to meet its contractual
          obligations with a combination of cash from operations and funds from the
          capital markets.
 
 *Changes
          in Cash
          Position*
 
 As
          of
          September 30, 2005, TE's cash and cash equivalents of $15,000 remained
          unchanged from December 31, 2004.
 
 *Cash
          Flows From
          Operating Activities*
 
 Cash
          provided from
          operating activities during the third quarter and first nine months of
          2005,
          compared with the corresponding period of 2004 were as follows:
  **Three
                    Months Ended**
                
                **Nine
                    Months Ended****September
                    30,**
                
                **September
                    30,****Operating
                    Cash Flows**
                
                **2005**
                
                **2004**
                
                **2005**
                
                **2004*****(In
                    millions)***Cash
                    earnings(1)
                
                $
                84
                
                $
                77
                
                $
                140
                
                $
                152Pension
                    trust
                    contribution(2)
                
                
                --
                
                
                (8
                )
                
                --
                
                
                (8
                )Working
                    capital and other
                
                
                --
                
                
                55
                
                
                (27
                )
                
                71Total
                    cash
                    flows from operating activities
                
                $
                84
                
                $
                124
                
                $
                113
                
                $
                215(1)Cash earnings are a non-GAAP measure (see reconciliation
                    below).(2)Pension trust contribution net of $5 million of income
                    tax
                    benefits.
   Cash
          earnings, as
          disclosed 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. The following table reconciles cash earnings with net
          income.
 105
 
 
 **Three
                  Months Ended**
              
              **Nine
                  Months Ended****September
                  30,**
              
              **September
                  30,****Reconciliation
                  of Cash Earnings**
              
              **2005**
              
              **2004**
              
              **2005**
              
              **2004*****(In
                  millions)***Net
                  income
                  (GAAP)
              
              $
              42
              
              $
              24
              
              $
              50
              
              $
              54Non-cash
                  charges (credits):Provision
                  for
                  depreciation
              
              
              19
              
              
              15
              
              
              49
              
              
              43Amortization
                  of regulatory assets
              
              
              40
              
              
              41
              
              
              108
              
              
              102Deferral
                  of
                  new regulatory assets
              
              
              (20
              )
              
              (12
              )
              
              (42
              )
              
              (30
              )Nuclear
                  fuel
                  and capital lease amortization
              
              
              6
              
              
              7
              
              
              14
              
              
              18Amortization
                  of electric service obligation
              
              
              (2
              )
              
              --
              
              
              (3
              )
              
              -Deferred
                  rents and above-market lease liability
              
              
              10
              
              
              10
              
              
              (34
              )
              
              (27
              )Deferred
                  income taxes and investment tax credits, net
              
              
              (13
              )
              
              (8
              )
              
              (5
              )
              
              (14
              )Accrued
                  retirement benefits obligations
              
              
              2
              
              
              1
              
              
              4
              
              
              5Accrued
                  compensation, net
              
              
              -
              
              
              (1
              )
              
              (1
              )
              
              1Cash
                  earnings
                  (Non-GAAP)
              
              $
              84
              
              $
              77
              
              $
              140
              
              $
              152
 Net
          cash provided
          from operating activities decreased by $40 million in the third quarter
          of 2005
          from the third quarter of 2004 as a result of a $55 million decrease from
          working capital, partially offset by a $7 million increase in cash earnings
          as
          described above and under “Results of Operations” and the absence of an $8
          million after-tax voluntary pension trust contribution made in the third
          quarter
          of 2004. Net cash provided from operating activities decreased by $102
          million
          in the first nine months of 2005 compared to the same period last year
          as a
          result of a $98 million change in working capital and a $12 million decrease
          in
          cash earnings as described above and under “Results of Operations,” partially
          offset by the absence of an $8 million after-tax voluntary pension trust
          contribution made in 2004. The change in working capital for both periods
          was
          primarily due to changes in accounts payable, accrued taxes and receivables,
          partially offset in the nine-month period of 2005 by funds received for
          prepaid
          electric service under the Ohio Schools Council’s Energy for Education Program
          that began in the second quarter of 2005.
 
 *Cash
          Flows From
          Financing Activities*
 
 Net
          cash used for
          financing activities decreased by $48 million and increased by $1 million
          in the
          third quarter and first nine months of 2005, respectively, as compared
          to the
          same periods of 2004. The activities in both periods reflect an increase
          in net
          debt redemptions and preferred stock redemptions. The increase in the nine-month
          period of 2005 also included a $10 million increase in common stock dividends
          to
          FirstEnergy.
 
 On
          July 1,
          2005, TE redeemed all of its 1,200,000 outstanding shares of 7.00% Series
          A
          preferred stock at $25.00 per share, plus accrued dividends to the date
          of
          redemption. TE also repurchased $37 million of pollution control revenue
          bonds
          on September 1, 2005, with the intent to remarket them by the end
          of the
          first quarter of 2006.
 
 TE
          had $53 million
          of cash and temporary investments (which included short-term notes receivable
          from associated companies) and $378 million of short-term indebtedness
          as of
          September 30, 2005. TE has authorization from the PUCO to incur
          short-term
          debt of up to $500 million (including the utility money pool described
          below).
          As of October 24, 2005, TE had the capability to issue $1.0 billion of
          additional FMB on the basis of property additions and retired bonds under
          the
          terms of its mortgage indenture following the recently completed intra-system
          transfer of fossil generating plants (See Note 17). Based upon applicable
          earnings coverage tests, TE could issue up to $1.15 billion of preferred
          stock
          (assuming no additional debt was issued) as of September 30, 2005.
          It is
          estimated that the annualized impact of the intra-system transfer of fossil
          generating plants will reduce the capability of TE to issue preferred stock
          by
          approximately $16 million.
 
 On
          June 14,
          2005, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI,
          as Borrowers, entered into a syndicated $2 billion five-year revolving
          credit
          facility. Borrowings under the facility are available to each Borrower
          separately and will mature on the earlier of 364 days from the date of
          borrowing
          and the commitment termination date, as the same may be extended. TE's
          borrowing
          limit under the facility is $250 million.
 
 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 third quarter of 2005 was 3.50%.
   106




TE’s
          access to
          capital markets and costs of financing are dependent on the ratings of
          its
          securities and the securities of FirstEnergy.
 
 On
          July 18,
          2005, Moody’s revised its rating outlook on FirstEnergy and its subsidiaries to
          positive from stable. Moody’s stated that the revision to FirstEnergy’s outlook
          resulted from steady financial improvement and steps taken by management
          to
          improve operations, including the stabilization of its nuclear operations.
          Moody’s further stated that the revision in their outlook recognized
          management’s regional strategy of focusing on its core utility businesses and
          the improvement in FirstEnergy’s credit profile stemming from the application of
          free cash flow toward debt reduction. Moody’s noted that a ratings upgrade could
          be considered if FirstEnergy continues to achieve planned improvements
          in its
          operations and balance sheet.
 
 On October 3,
          2005, S&P raised its corporate credit rating on FirstEnergy and the EUOC to
          'BBB' from 'BBB-'. At the same time, S&P raised the senior unsecured ratings
          at the holding company to 'BBB-' from 'BB+' and each of the EUOC by one
          notch
          above the previous rating. S&P noted that the upgrade followed the
          continuation of a good operating track record, specifically for the nuclear
          fleet through the third quarter 2005. S&P also stated that FirstEnergy’s
          rating reflects the benefits of supportive regulation, low-cost base load
          generation fleet, low-risk transmission and distribution operations and
          rate
          certainty in Ohio. FirstEnergy’s ability to consistently generate free cash
          flow, good liquidity, and an improving financial profile were also noted
          as
          strengths.
 
 *Cash
          Flows From
          Investing Activities*
 
 Net
          cash used for
          investing activities increased by $9 million in the third quarter of 2005
          compared with from the same period of 2004. Net cash provided from investing
          activities increased by $105 million in the first nine months of 2005,
          from the
          same period of 2004. These increases were primarily due to changes from
          loan
          activity with associated companies during the periods, partially offset
          by
          increased property additions in the nine-month period.
 
 In
          the last quarter
          of 2005, TE’s capital spending is expected to be about $25 million. These cash
          requirements are expected to be satisfied from internal cash and short-term
          borrowings. TE’s
          capital
          spending for the period 2005-2007 is expected to be about $192 million,
          of which
          approximately $64 million applies to 2005.
 
 **FirstEnergy
          Intra-System Generation Asset Transfers**
  On
          May 18,
          2005, OE, CEI and TE, entered into certain agreements implementing a series
          of
          intra-system generation asset transfers. When fully completed, the asset
          transfers will result in the respective undivided ownership interests of
          the
          Ohio Companies in FirstEnergy’s nuclear and non-nuclear plants being owned by
          NGC and FGCO, respectively. The generating plant interests that are being
          transferred do 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 transfer of non-nuclear generation assets to FGCO.
          TE
          currently expects to complete the transfer of nuclear generation assets
          to NGC
          at book value before the end of 2005. Consummation of the nuclear transfer
          remains subject to necessary regulatory approvals.
 
 These
          transactions
          are being undertaken in connection with the Ohio Companies’ restructuring plans
          that were approved by the PUCO under applicable Ohio electric utility
          restructuring legislation. Consistent with the restructuring plans, generation
          assets that had been owned by the Ohio Companies were required to be separated
          from the regulated delivery business of those companies through transfer
          to a
          separate corporate entity. FENOC currently operates and maintains the nuclear
          generation assets to be transferred. FGCO, as lessee under a Master Facility
          Lease, leased, operated and maintained the non-nuclear generation assets
          that it
          now owns. The transactions will essentially complete the divestitures
          contemplated by the restructuring plans by transferring the ownership interests
          to NGC and FGCO, respectively, without impacting the operation of the plants.
 
 See
          Note 17 to the
          consolidated financial statements for TE’s disclosure of the assets held for
          sale as of September 30, 2005.
 
 **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, 2005, the present value of these operating
          lease commitments, net of trust investments, totaled $541 million.
 
 TE
          sells
          substantially all of its retail customer receivables to CFC, a wholly owned
          subsidiary of CEI. As of June 16, 2005, the CFC receivables financing
          structure was renewed and restructured from an off-balance sheet transaction
          to
          an on-balance sheet transaction. Under the new structure, any borrowings
          under
          the facility appear on the balance sheet as short-term debt.
 107
 
 **Equity
          Price Risk**
 
 Included
          in TE’s
          nuclear decommissioning trust investments are marketable equity securities
          carried at their market value of approximately $217 million and $188 million
          as
          of September 30, 2005 and December 31, 2004, respectively.
          A
          hypothetical 10% decrease in prices quoted by stock exchanges would result
          in a
          $22 million reduction in fair value as of September 30, 2005. Changes
          in
          the fair value of these investments are recorded in OCI unless recognized
          as a
          result of sales.
 
 **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***
 
 In
          2001, Ohio
          customer rates were restructured to establish separate charges for transmission,
          distribution, transition cost recovery and a generation-related component.
          When
          one of TE's customers elects to obtain power from an alternative supplier,
          TE
          reduces the customer's bill with a "generation shopping credit," based
          on the
          generation component plus an incentive, and the customer receives a generation
          charge from the alternative supplier. TE has continuing PLR responsibility
          to
          its franchise customers through December 31, 2008 unless the PUCO
          accepts
          future competitive bid results prior to the end of that period under the
          revised
          RSP.
 
 As
          part of TE's
          transition plan, it is obligated to supply electricity to customers who
          do not
          choose an alternative supplier. TE is also required to provide 160 MW of
          low
          cost supply (MSG) to unaffiliated alternative suppliers who serve customers
          within its service area. FES acts as an alternate supplier for a portion
          of the
          load in TE's franchise area.
 
 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 competitive
          bid
          process. The RSP was filed by the Ohio Companies to establish generation
          service
          rates beginning January 1, 2006, in response to PUCO 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 this proceeding as well as the associated entries on rehearing. On
          September 28, 2005, the Ohio Supreme Court heard oral argument on
          the
          appeals.
 
 On
          May 27,
          2005, TE filed an application with the PUCO to establish a GCAF rider under
          its
          RSP. The application seeks to implement recovery of increased fuel costs
          from
          2006 through 2008 applicable to TE’s retail customers through a tariff rider to
          be implemented January 1, 2006. The application reflects projected
          increases in fuel costs in 2006 compared to 2002 baseline costs. The new
          rider,
          after adjustments made in testimony, is seeking to recover all costs above
          the
          baseline (approximately $88 million in 2006 for all the Ohio Companies).
          Various
          parties including the OCC have intervened in this case and the case has
          been
          consolidated with the RCP application discussed below.
 
 On
          September 9, 2005, TE filed an application with the PUCO that, if
          approved,
          would supplement its existing RSP with an RCP. On September 27,
          2005, the
          PUCO granted FirstEnergy's motion to consolidate the GCAF rider application
          with
          the RCP proceedings and set hearings for the consolidated cases to begin
          November 29, 2005. The RCP is designed to provide customers with
          more
          certain rate levels than otherwise available under the RSP during the plan
          period. Major provisions of the RCP include:
 
 ·
                Maintain
                    the
                    existing level of base distribution rates through December 31,
                    2008
                    for TE;
 
 ·
                Defer
                    and
                    capitalize 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;
 
 ·
                Adjust
                    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;
 
 ·
                Reduce
                    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
 108
  ·
                Recover
                    increased fuel costs 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. TE may defer and capitalize increased fuel costs above
                    the
                    amount collected
                  through
                    the
                    fuel recovery mechanism.
 
 Under
          provisions of
          the RSP, t he
          PUCO may require
          TE to undertake, no more often than annually, a competitive bid process
          to
          secure generation for the years 2007 and 2008. On July 22, 2005,
          FirstEnergy filed a competitive bid process for the period beginning in
          2007
          that is similar to the competitive bid process approved by the PUCO for
          TE in
          2004, which resulted in the PUCO accepting no bids. Any acceptance of future
          competitive bid results would terminate the RSP pricing, with no accounting
          impacts to the RSP, and not until twelve months after the PUCO authorizes
          such
          termination. On September 28, 2005, the PUCO issued an Entry that
          essentially approved the Ohio Companies’ filing but delayed the proposed timing
          of the competitive bid process by four months, calling for the auction
          to be
          held on March 21, 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 seeks recovery of these costs beginning January 1, 2006.
          At the
          time of filing the application, these costs were estimated to be approximately
          $0.1 million per year; however, TE anticipates that this amount will increase.
          TE requested that these costs be recovered through a rider that would be
          effective on January 1, 2006 and adjusted each July 1 thereafter.
          TE
          reached a settlement with OCC, PUCO staff, Industrial Energy Users - Ohio
          and
          OPAE. The only other party in this proceeding, Dominion Retail, Inc., agreed
          not
          to oppose the settlement. This settlement, which was filed with the PUCO
          on
          July 22, 2005, provides for the rider recovery requested by TE,
          with
          carrying charges applied in the subsequent year’s rider for any over or under
          collection while the then-current rider is in effect. The PUCO approved
          the
          settlement stipulation on August 31, 2005. The incremental Transmission
          and
          Ancillary service revenues expected to be recovered from January through
          June
          2006 are approximately $6.7 million. This value includes the recovery of
          the
          2005 deferred MISO expenses as described below. In May 2006, TE will file
          a
          modification to the rider which will determine revenues from July 2006
          through
          June 2007.
 
 The
          second
          application seeks 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 TE to defer incremental transmission and ancillary
          service-related charges incurred as a participant in the 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 31, 2004 was denied. The PUCO also authorized TE to accrue
          carrying charges on the deferred balances. An application filed with the
          PUCO to
          recover these deferred charges over a five-year period through the rider,
          beginning in 2006, was approved in a PUCO order issued on August 31,
          2005.
          The OCC, OPAE and TE each filed applications for rehearing. TE sought authority
          to defer the transmission and ancillary service related costs incurred
          during
          the period October 1, 2003 through December 29, 2004, while
          both OCC
          and OPAE sought to have the PUCO deny deferral of all costs. On
          July 6,
          2005, the PUCO denied TE's and OCC’s applications and, at the request of TE,
          struck as untimely OPAE’s application. The OCC filed a notice of appeal with the
          Ohio Supreme Court on August 31, 2005. On September 30, 2005, in accordance
          with
          appellate procedure, the PUCO filed with the Ohio Supreme Court the record
          in
          this case. The Companies' brief will be due thirty days after the OCC files
          its
          brief, which, absent any time extensions, must be filed no later than November
          9, 2005.
 
 TE
          records as
          regulatory assets costs which have been authorized by the PUCO and the
          FERC for
          recovery from customers in future periods and, without such authorization,
          the
          costs would have been charged to income when incurred. TE's regulatory
          assets as
          of September 30, 2005 and December 31, 2004, were $310 million
          and
          $375 million, respectively. TE is deferring customer shopping incentives
          and
          interest costs as new regulatory assets in accordance with its transition
          and
          rate stabilization plans. These regulatory assets total $122 million as
          of
          September 30, 2005 and, under the RSP, will be recovered through
          a
          surcharge rate equal to the RTC rate in effect when the transition costs
          have
          been fully recovered. See Note 14 “Regulatory Matters - Ohio” for the estimated
          net amortization of regulatory transition costs and deferred shopping incentive
          balances under the proposed RCP and current RSP.
 
 See
          Note 14 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.
 
 FirstEnergy
          plans
          to issue a report regarding its response to air emission requirements.
          FirstEnergy expects to complete the report by December 1,
          2005.
 109
 *National
          Ambient Air Quality Standards*
  In
          July 1997, the
          EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS
          for fine
          particulate matter. On March 10, 2005, the EPA finalized the "Clean
          Air
          Interstate Rule" covering a total of 28 states (including 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
          nonattainment 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 regulation 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 )
          in all cases from
          the 2003 levels. TE's Ohio and Pennsylvania fossil-fired generation facilities
          will be subject to the caps on SO 2 and 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 TE 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. On March 14, 2005,
          the EPA
          finalized the “Clean Air Mercury Rule,” 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
          the CAIR
          and the Clean Air Mercury rule have been challenged in the United States
          Court
          of Appeals for the District of Columbia. Future cost of compliance
          with
          these regulations may be substantial.
 
 *Climate
          Change*
 
 In
          December 1997,
          delegates to the United Nations' climate summit in Japan adopted an agreement,
          the Kyoto Protocol (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 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 percent through 2012. The
          Energy
          Policy Act of 2005 established a Committee on Climate Change Technology
          to
          coordinate federal climate change activities and promote the development
          and
          deployment of GHG reducing technologies.
 
 TE
          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 KWH
          of electricity generated by TE is lower than many regional competitors
          due to
          TE's diversified generation sources which include low or non-CO 2 emitting gas-fired
          and nuclear generators.
 
 *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,
          2005,
          based on estimates of the total costs of cleanup, TE's proportionate
          responsibility for such costs and the financial ability of other nonaffiliated
          entities to pay. Included in Other Noncurrent Liabilities are accrued
          liabilities aggregating approximately $0.2 million as of September 30,
          2005.
 
 See
          Note 13(B) to
          the consolidated financial statements for further details and a complete
          discussion of environmental matters.
 110
 
 ***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 and its
          subsidiaries. The other material items not otherwise discussed above are
          described below.
 
 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 concludes, 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 website (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 also is proceeding with
          the
          implementation of the recommendations regarding enhancements to regional
          reliability 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, and therefore FirstEnergy has not accrued a liability as of
          September 30, 2005 for any expenditures in excess of those actually
          incurred through that date. FirstEnergy notes, however, that FERC or other
          applicable government agencies and reliability coordinators may take a
          different
          view as to recommended enhancements or may recommend additional enhancements
          in
          the future that could require additional, material expenditures. Finally,
          the
          PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to
          control room computer hardware and software and enhancements to the training
          of
          control room operators, before determining the next steps, if any, in the
          proceeding.
 
 FirstEnergy
          companies also are defending six separate complaint cases before the PUCO
          relating to the August 14, 2003 power outage. Two such cases were originally
          filed in Ohio State courts but subsequently dismissed for lack of subject
          matter
          jurisdiction and further appeals were unsuccessful. In both such 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. Of the four other pending PUCO complaint cases, three were
          filed by
          various insurance carriers either in their own name as subrogees or in
          the name
          of their insured. In each such case, the carriers seek reimbursement against
          various FirstEnergy companies (and, in one case, against PJM, MISO and
          American
          Electric Power Co. as well) for claims they paid to their insureds allegedly
          due
          to 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 fourth
          case
          involves the claim of a non-customer seeking reimbursement for losses incurred
          when its store was burglarized on August 14, 2003. In addition to these
          six
          cases, the Ohio Companies were named as respondents in a regulatory proceeding
          that was initiated at the PUCO in response to complaints alleging failure
          to
          provide reasonable and adequate service stemming primarily from the
          August 14, 2003 power outages. No estimate of potential liability
          has been
          undertaken for any of these cases.
 
 One
          complaint was
          filed on August 25, 2004 against FirstEnergy in the New York State Supreme
          Court. In this case, several plaintiffs in the New York City metropolitan
          area
          allege that they suffered damages as a result of the August 14,
          2003 power
          outages. None of the plaintiffs are customers of any FirstEnergy affiliate.
          FirstEnergy's motion to dismiss the case was granted on September 26,
          2005.
          Additionally, FirstEnergy Corp. was named in a complaint filed in Michigan
          State
          Court by an individual who is not a customer of any FirstEnergy company.
          A
          responsive pleading to this matter is not due until on or about December
          1,
          2005. No estimate of potential liability has been undertaken in this matter.
 
 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.
 111
  FENOC
          received a
          subpoena in late 2003 from a grand jury sitting in the United States District
          Court for the Northern District of Ohio, Eastern Division requesting the
          production of certain documents and records relating to the inspection
          and
          maintenance of the reactor vessel head at the Davis-Besse Nuclear Power
          Station,
          in which TE has a 48.62% interest. On December 10, 2004, FirstEnergy
          received a letter from the United States Attorney's Office stating that
          FENOC is
          a target of the federal grand jury investigation into alleged false statements
          made to the NRC in the Fall of 2001 in response to NRC Bulletin 2001-01.
          The
          letter also said that the designation of FENOC as a target indicates that,
          in
          the view of the prosecutors assigned to the matter, it is likely that federal
          charges will be returned against FENOC by the grand jury. On February 10,
          2005, FENOC received an additional subpoena for documents related to root
          cause
          reports regarding reactor head degradation and the assessment of reactor
          head
          management issues at Davis-Besse. On May 11,
          2005, FENOC received a subpoena for documents related to outside meetings
          attended by Davis-Besse personnel on corrosion and cracking of control
          rod drive
          mechanisms and additional root cause evaluations.
 
 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 described
          above. TE
          accrued $1.0 million for a potential fine prior to 2005 and accrued the
          remaining liability for its share of the proposed fine of $1.65 million
          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.
 
 If
          it were
          ultimately determined that FirstEnergy or its subsidiaries has legal liability
          based on events surrounding Davis-Besse, it could have a material adverse
          effect
          on FirstEnergy's or any of its subsidiaries' financial condition, results
          of
          operations and cash flows.
 
 Effective
          July 1, 2005 the NRC oversight panel for Davis-Besse was terminated
          and
          Davis-Besse returned to the standard NRC reactor oversight process. At
          that
          time, NRC inspections were augmented to include inspections to support
          the NRC's
          Confirmatory Order dated March 8, 2004 that was issued at the time
          of
          startup and to address an NRC White Finding related to the performance
          of the
          emergency sirens.
 
 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 effective corrective action. FENOC operates the Perry Nuclear Power
          Plant,
          in which TE has a 19.91% interest (however,
          see Note
          17 regarding FirstEnergy’s pending intra-system generation asset transfers,
          which include owned portions of the 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
          May 26,
          2005, the NRC held a public meeting to discuss its oversight of the Perry
          Plant.
          While the NRC stated that the plant continued to operate safely, the NRC
          also
          stated that the overall performance had not substantially improved since
          the
          heightened inspection was initiated. The NRC reiterated this conclusion
          in its
          mid-year assessment letter dated August 30, 2005. On September 28,
          2005,
          the NRC sent a CAL to FENOC describing commitments that FENOC had made
          to
          improve the performance of Perry 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. 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. As a result, these matters
          could have a material adverse effect on FirstEnergy's or its subsidiaries'
          financial condition, results of operations and cash flows.
 
 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 TE, 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 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. 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. An
          adverse ruling
          could negatively affect full recovery of transition charges by TE. 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.
          It is unknown when the PUCO will rule on this case.
 
 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 13(C) to
          the consolidated financial statements for further details and a complete
          discussion of other legal proceedings.
 
 **New
          Accounting Standards and Interpretations**
 
 *EITF
          Issue
          04-13, "Accounting for Purchases and Sales of Inventory with the Same
          Counterparty"*
  In
          September 2005,
          the EITF reached a final consensus on Issue 04-13 concluding that two or
          more
          legally separate exchange transactions with the same counterparty should
          be
          combined and considered as a single arrangement for purposes of applying
          APB 29,
          when the transactions were entered into "in contemplation" of one another.
          If
          two transactions are combined and considered a single arrangement, the
          EITF
          reached a consensus that an exchange of inventory should be accounted for
          at
          fair value. Although electric power is not capable of being held in inventory,
          there is no substantive conceptual distinction between exchanges involving
          power
          and other storable inventory. Therefore, TE will adopt this EITF effective
          for
          new arrangements entered into, or modifications or renewals of existing
          arrangements, in interim or annual periods beginning after March 15, 2006.
 
 *EITF
                    Issue No. 05-6, "Determining the Amortization Period for Leasehold
                    Improvements Purchased after Lease Inception or Acquired in a
                    Business
                    Combination"*
  In
          June 2005, the
          EITF reached a consensus on the application guidance for Issue 05-6. EITF
          05-6
          addresses the amortization period for leasehold improvements that were
          either
          acquired in a business combination or placed in service significantly after
          and
          not contemplated at or near the beginning of the initial lease term. For
          leasehold improvements acquired in a business combination, the amortization
          period is the shorter of the useful life of the assets or a term that includes
          required lease periods and renewals that are deemed to be reasonably assured
          at
          the date of acquisition. Leasehold improvements that are placed in service
          significantly after and not contemplated at or near the beginning of the
          lease
          term should be amortized over the shorter of the useful life of the assets
          or a
          term that includes required lease periods and renewals that are deemed
          to be
          reasonably assured at the date the leasehold improvements are purchased.
          This
          EITF was effective July 1, 2005 and is consistent with TE’s current
          accounting.
 
 *FIN
          47,
“Accounting for Conditional Asset Retirement Obligations - an interpretation
          of
          FASB Statement No. 143”*
  On
          March 30,
          2005, the FASB issued FIN 47 to clarify the scope and timing of liability
          recognition for conditional asset retirement obligations. Under this
          interpretation, companies are required to recognize a liability for the
          fair
          value of an asset retirement obligation that is conditional on a future
          event,
          if the fair value of the liability can be reasonably estimated. In instances
          where there is insufficient information to estimate the liability, the
          obligation is to be recognized in the first period in which sufficient
          information becomes available to estimate its fair value. If the fair value
          cannot be reasonably estimated, that fact and the reasons why must be disclosed.
          This Interpretation is effective for TE in the fourth quarter of 2005.
          TE is
          currently evaluating the effect this Interpretation will have on its financial
          statements.
 
 *SFAS
                    154
                    - “Accounting Changes and Error Corrections - a replacement of APB
                    Opinion
                    No. 20 and FASB Statement No.
                    3”*
 
 In
          May 2005, the
          FASB issued SFAS 154 to change the requirements for accounting and reporting
          a
          change in accounting principle. It applies to all voluntary changes in
          accounting principle and to changes required by an accounting pronouncement
          when
          that pronouncement does not include specific transition provisions. This
          Statement requires retrospective application to prior periods’ financial
          statements of changes in accounting principle, unless it is impracticable
          to
          determine either the period-specific effects or the cumulative effect of
          the
          change. In those instances, this Statement requires that the new accounting
          principle be applied to the balances of assets and liabilities as of the
          beginning of the earliest period for which retrospective application is
          practicable and that a corresponding adjustment be made to the opening
          balance
          of retained earnings (or other appropriate components of equity or net
          assets in
          the statement of financial position) for that period rather than being
          reported
          in the Consolidated Statements of Income. This Statement also requires
          that a
          change in depreciation, amortization, or depletion method for long-lived,
          nonfinancial assets be accounted for as a change in accounting estimate
          affected
          by a change in accounting principle. The provisions of this Statement are
          effective for accounting changes and corrections of errors made in fiscal
          years
          beginning after December 15, 2005. TE will adopt this Statement
          effective
          January 1, 2006.
 113
 *SFAS
                    153,
                    “Exchanges of Nonmonetary Assets - an amendment of APB Opinion
                    No.
                    29”*
 
 In
          December 2004,
          the FASB issued SFAS 153 amending APB 29, which was based on the principle
          that
          nonmonetary assets should be measured based on the fair value of the assets
          exchanged. The guidance in APB 29 included certain exceptions to that principle.
          SFAS 153 eliminates the exception from fair value measurement for nonmonetary
          exchanges of similar productive assets and replaces it with an exception
          for
          exchanges that do not have commercial substance. This Statement specifies
          that a
          nonmonetary exchange has commercial substance if the future cash flows
          of the
          entity are expected to change significantly as a result of the exchange.
          The
          provisions of this Statement are effective January 1, 2006 for TE.
          This FSP
          is not expected to have a material impact on TE’s financial
          statements.
 
 *SFAS
          151,
“Inventory Costs - an amendment of ARB No. 43, Chapter 4”*
 
 In
          November 2004,
          the FASB issued SFAS 151 to clarify the accounting for abnormal amounts
          of idle
          facility expense, freight, handling costs and wasted material (spoilage).
          Previous guidance stated that in some circumstances these costs may be
“so
          abnormal” that they would require treatment as current period costs. SFAS 151
          requires abnormal amounts for these items to always be recorded as current
          period costs. In addition, this Statement requires that allocation of fixed
          production overheads to the cost of conversion be based on the normal capacity
          of the production facilities. The provisions of this statement are effective
          for
          inventory costs incurred by TE beginning January 1, 2006. TE is
          currently
          evaluating this Standard and does not expect it to have a material impact
          on its
          financial statements.
 
 *FSP
          FAS 115-1,
          "The Meaning of Other-Than-Temporary Impairment and its Application to
          Certain
          Investments"*
 
 In
          September 2005,
          the FASB finalized and renamed EITF 03-1 and 03-1-a to FSP FAS 115-1. FSP
          FAS
          115-1 will (1) supersede Issue 03-1 and EITF topic No. D-44, "Recognition
          of
          Other Than Temporary Impairment upon the Planned Sale of a Security Whose
          Cost
          Exceeds Fair Value," (2) clarify that an investor should recognize an impairment
          loss no later than when the impairment is deemed other than temporary,
          even if a
          decision to sell has not been made, and (3) be effective for
          other-than-temporary impairment and analyses conducted in periods beginning
          after September 15, 2005. The FASB expects to issue this FSP in
          the fourth
          quarter of 2005, which would require prospective application with an effective
          date for reporting periods beginning after December 15, 2005. TE is currently
          evaluating this FSP and any impact on its investments.
 
 114
 
 **PENNSYLVANIA
                    POWER COMPANY****CONSOLIDATED
                    STATEMENTS OF INCOME AND COMPREHENSIVE INCOME****(Unaudited)****Three
                    Months Ended**
                
                **Nine
                    Months Ended****September
                    30,**
                
                **September
                    30,****2005**
                
                **2004**
                
                **2005**
                
                **2004*****(In
                    thousands)*****STATEMENTS
                    OF INCOME****OPERATING
                    REVENUES**
                
                $
                145,540
                
                $
                143,340
                
                $
                414,306
                
                $
                420,578**OPERATING
                    EXPENSES AND TAXES:**Fuel
                
                
                6,205
                
                
                6,347
                
                
                17,351
                
                
                18,408Purchased
                    power
                
                
                42,242
                
                
                44,096
                
                
                131,948
                
                
                136,699Nuclear
                    operating costs
                
                
                16,997
                
                
                19,934
                
                
                56,710
                
                
                55,737Other
                    operating costs
                
                
                19,030
                
                
                16,212
                
                
                48,541
                
                
                45,371Provision
                    for
                    depreciation
                
                
                3,847
                
                
                3,556
                
                
                11,351
                
                
                10,390Amortization
                    of regulatory assets
                
                
                9,784
                
                
                9,979
                
                
                29,499
                
                
                30,082General
                    taxes
                
                
                6,836
                
                
                6,416
                
                
                19,752
                
                
                17,538Income
                    taxes
                
                
                17,402
                
                
                16,541
                
                
                43,055
                
                
                46,425Total
                    operating expenses and taxes
                
                
                122,343
                
                
                123,081
                
                
                358,207
                
                
                360,650**OPERATING
                    INCOME**
                
                
                23,197
                
                
                20,259
                
                
                56,099
                
                
                59,928**OTHER
                    INCOME (net of income taxes)**
                
                
                549
                
                
                745
                
                
                623
                
                
                2,287**NET
                    INTEREST CHARGES:**Interest
                    expense
                
                
                2,371
                
                
                1,911
                
                
                7,477
                
                
                7,434Allowance
                    for
                    borrowed funds used during construction
                
                
                (1,665
                )
                
                (1,271
                )
                
                (4,508
                )
                
                (3,197
                )Net
                    interest
                    charges
                
                
                706
                
                
                640
                
                
                2,969
                
                
                4,237**NET
                    INCOME**
                
                
                23,040
                
                
                20,364
                
                
                53,753
                
                
                57,978**PREFERRED
                    STOCK DIVIDEND REQUIREMENTS**
                
                
                156
                
                
                639
                
                
                1,534
                
                
                1,919**EARNINGS
                    ON COMMON STOCK**
                
                $
                22,884
                
                $
                19,725
                
                $
                52,219
                
                $
                56,059**STATEMENTS
                    OF COMPREHENSIVE INCOME****NET
                    INCOME**
                
                $
                23,040
                
                $
                20,364
                
                $
                53,753
                
                $
                57,978**OTHER
                    COMPREHENSIVE INCOME**
                
                
                -
                
                
                -
                
                
                -
                
                
                -**TOTAL
                    COMPREHENSIVE INCOME**
                
                $
                23,040
                
                $
                20,364
                
                $
                53,753
                
                $
                57,978The
                    preceding
                    Notes to Consolidated Financial Statements as they relate to
                    Pennsylvania
                    Power Company are an integral part of these statements.
   115
 **PENNSYLVANIA
                    POWER COMPANY****CONSOLIDATED
                    BALANCE SHEETS****(Unaudited)****September
                    30,**
                
                **December
                    31,****2005**
                
                **2004*****(In
                    thousands)*****ASSETS****UTILITY
                    PLANT:**In
                    service
                
                $
                907,382
                
                $
                866,303Less
                    -
                    Accumulated provision for depreciation
                
                
                378,707
                
                
                356,020528,675
                
                
                510,283Construction
                    work in progress -Electric
                    plant
                
                
                133,790
                
                
                104,366Nuclear
                    fuel
                
                
                10,428
                
                
                3,362144,218
                
                
                107,728672,893
                
                
                618,011**OTHER
                    PROPERTY AND INVESTMENTS:**Nuclear
                    plant
                    decommissioning trusts
                
                
                146,706
                
                
                143,062Long-term
                    notes receivable from associated companies
                
                
                32,864
                
                
                32,985Other
                
                
                502
                
                
                722180,072
                
                
                176,769**CURRENT
                    ASSETS:**Cash
                    and cash
                    equivalents
                
                
                24
                
                
                38Notes
                    receivable from associated companies
                
                
                566
                
                
                431Receivables
                    -Customers
                    (less accumulated provisions of $1,066,000 and $888,000,respectively,
                    for uncollectible accounts)
                
                
                44,990
                
                
                44,282Associated
                    companies
                
                
                6,206
                
                
                23,016Other
                
                
                2,617
                
                
                1,656Materials
                    and
                    supplies, at average cost
                
                
                37,974
                
                
                37,923Prepayments
                    and other
                
                
                12,110
                
                
                8,924104,487
                
                
                116,270**DEFERRED
                    CHARGES**
                
                
                10,721
                
                
                10,106$
                968,173
                
                $
                921,156**CAPITALIZATION
                    AND LIABILITIES****CAPITALIZATION:**Common
                    stockholder's equity -Common
                    stock,
                    $30 par value, authorized 6,500,000 shares -6,290,000
                    shares outstanding
                
                $
                188,700
                
                $
                188,700Other
                    paid-in
                    capital
                
                
                65,035
                
                
                64,690Accumulated
                    other comprehensive loss
                
                
                (13,706
                )
                
                (13,706
                )Retained
                    earnings
                
                
                131,914
                
                
                87,695Total
                    common
                    stockholder's equity
                
                
                371,943
                
                
                327,379Preferred
                    stock
                
                
                14,105
                
                
                39,105Long-term
                    debt
                    and other long-term obligations
                
                
                121,170
                
                
                133,887507,218
                
                
                500,371**CURRENT
                    LIABILITIES:**Currently
                    payable long-term debt
                
                
                25,774
                
                
                26,524Short-term
                    borrowings -Associated
                    companies
                
                
                34,821
                
                
                11,852Accounts
                    payable -Associated
                    companies
                
                
                16,864
                
                
                46,368Other
                
                
                1,884
                
                
                1,436Accrued
                    taxes
                
                
                26,163
                
                
                14,055Accrued
                    interest
                
                
                1,635
                
                
                1,872Other
                
                
                8,491
                
                
                8,802115,632
                
                
                110,909**NONCURRENT
                    LIABILITIES:**Accumulated
                    deferred income taxes
                
                
                79,801
                
                
                93,418Asset
                    retirement obligation
                
                
                155,959
                
                
                138,284Retirement
                    benefits
                
                
                51,389
                
                
                49,834Regulatory
                    liabilities
                
                
                47,809
                
                
                18,454Other
                
                
                10,365
                
                
                9,886345,323
                
                
                309,876**COMMITMENTS
                    AND CONTINGENCIES (Note 13)**$
                968,173
                
                $
                921,156The
                    preceding
                    Notes to Consolidated Financial Statements as they relate to
                    Pennsylvania
                    Power Company are an integral part of these balance
                    sheets.
    116
  **PENNSYLVANIA
                    POWER COMPANY****CONSOLIDATED
                    STATEMENTS OF CASH FLOWS****(Unaudited)****Three
                    Months Ended**
                
                **Nine
                    Months Ended****September
                    30,**
                
                **September
                    30,****2005**
                
                **2004**
                
                **2005**
                
                **2004*****(In
                    thousands)*****CASH
                    FLOWS FROM OPERATING ACTIVITIES:**Net
                    income
                
                $
                23,040
                
                $
                20,364
                
                $
                53,753
                
                $
                57,978Adjustments
                    to reconcile net income to net cash fromoperating
                    activities -Provision
                    for depreciation
                
                
                3,847
                
                
                3,556
                
                
                11,351
                
                
                10,390Amortization
                    of regulatory assets
                
                
                9,784
                
                
                9,979
                
                
                29,499
                
                
                30,082Nuclear
                    fuel and other amortization
                
                
                4,634
                
                
                4,550
                
                
                12,912
                
                
                13,546Deferred
                    income taxes and investment tax credits, net
                
                
                (2,612
                )
                
                (501
                )
                
                (7,567
                )
                
                (2,852
                )Pension
                    trust contribution
                
                
                -
                
                
                (12,934
                )
                
                -
                
                
                (12,934
                )Decrease
                    (increase) in operating assets -Receivables
                
                
                4,303
                
                
                (30,285
                )
                
                15,141
                
                
                (10,551
                )Materials
                    and
                    supplies
                
                
                755
                
                
                (1,078
                )
                
                (51
                )
                
                (3,374
                )Prepayments
                    and other current assets
                
                
                5,074
                
                
                4,164
                
                
                (3,186
                )
                
                (3,977
                )Increase
                    (decrease) in operating liabilities -Accounts
                    payable
                
                
                (9,161
                )
                
                40,306
                
                
                (29,056
                )
                
                21,678Accrued
                    taxes
                
                
                5
                
                
                (2,485
                )
                
                12,108
                
                
                2,301Accrued
                    interest
                
                
                (353
                )
                
                (986
                )
                
                (237
                )
                
                (2,415
                )Other
                
                
                564
                
                
                1,353
                
                
                1,027
                
                
                5,294Net
                    cash
                    provided from operating activities
                
                
                39,880
                
                
                36,003
                
                
                95,694
                
                
                105,166**CASH
                    FLOWS FROM FINANCING ACTIVITIES:**New
                    Financing
                    -Short-term
                    borrowings, net
                
                
                -
                
                
                -
                
                
                22,969
                
                
                10,789Equity
                    contribution from parent
                
                
                -
                
                
                25,000
                
                
                -
                
                
                25,000Redemptions
                    and Repayments -Preferred
                    stock
                
                
                -
                
                
                -
                
                
                (37,750
                )
                
                -Long-term
                    debt
                
                
                (39
                )
                
                (20,508
                )
                
                (849
                )
                
                (63,297
                )Short-term
                    borrowings, net
                
                
                (10,776
                )
                
                (11,414
                )
                
                -
                
                
                -Dividend
                    Payments -Common
                    stock
                
                
                -
                
                
                -
                
                
                (8,000
                )
                
                (23,000
                )Preferred
                    stock
                
                
                (156
                )
                
                (639
                )
                
                (1,534
                )
                
                (1,919
                )Net
                    cash used
                    for financing activities
                
                
                (10,971
                )
                
                (7,561
                )
                
                (25,164
                )
                
                (52,427
                )**CASH
                    FLOWS FROM INVESTING ACTIVITIES:**Property
                    additions
                
                
                (28,537
                )
                
                (24,670
                )
                
                (69,630
                )
                
                (56,080
                )Contributions
                    to nuclear decommissioning trusts
                
                
                (399
                )
                
                (399
                )
                
                (1,196
                )
                
                (1,196
                )Loan
                    repayments from (loans to) associated companies
                
                
                (187
                )
                
                (36
                )
                
                (14
                )
                
                5,975Other
                
                
                214
                
                
                (3,337
                )
                
                296
                
                
                (1,440
                )Net
                    cash used
                    for investing activities
                
                
                (28,909
                )
                
                (28,442
                )
                
                (70,544
                )
                
                (52,741
                )Net
                    change in
                    cash and cash equivalents
                
                
                -
                
                
                -
                
                
                (14
                )
                
                (2
                )Cash
                    and cash
                    equivalents at beginning of period
                
                
                24
                
                
                38
                
                
                38
                
                
                40Cash
                    and cash
                    equivalents at end of period
                
                $
                24
                
                $
                38
                
                $
                24
                
                $
                38The
                    preceding
                    Notes to Consolidated Financial Statements as they relate to
                    Pennsylvania
                    Power Company are an integral part of these statements.
 117




***Report
          of Independent Registered Public Accounting Firm***
 
 
 
 
 
 
 
 
 
 To
          the Stockholders
          and Board of
 Directors
          of
          Pennsylvania Power Company:
 
 We
          have reviewed
          the accompanying consolidated balance sheet of Pennsylvania Power Company
          and
          its subsidiary as of September 30, 2005, and the related consolidated
          statements of income and comprehensive income and cash flows for each of
          the
          three-month and nine-month periods ended September 30, 2005 and
          2004. 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
          previously
          audited, in accordance with the standards of the Public Company Accounting
          Oversight Board (United States), the consolidated balance sheet as of
          December 31, 2004, and the related consolidated statements of income,
          capitalization, common stockholder’s 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,
          2004 and the effectiveness of the Company’s internal control over financial
          reporting as of December 31, 2004; 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) to
          those consolidated financial statements) dated March 7, 2005, 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 information
          as of December 31, 2004, is fairly stated in all material respects
          in
          relation to the consolidated balance sheet from which it has been
          derived.
 
 
 
 
 PricewaterhouseCoopers
          LLP
 Cleveland,
          Ohio
 November
          1,
          2005
 118
  **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 provides power directly to wholesale customers under
          previously negotiated contracts. Penn has unbundled the price of electricity
          into its component elements - including generation, transmission, distribution
          and transition charges. Its power supply requirements are provided by FES
          - an
          affiliated company.
 
 **Results
          of Operations**
 
 Earnings
          on common
          stock in the third quarter of 2005 increased to $23 million from $20 million
          in
          the third quarter of 2004. The increased earnings resulted primarily from
          higher
          operating revenues and lower operating expenses and taxes. Earnings on
          common
          stock for the first nine months of 2005 decreased to $52 million from $56
          million for the same period of 2004. The lower earnings resulted primarily
          from
          a decrease in operating revenues and other income, partially offset by
          lower
          operating expenses and taxes and lower net interest charges.
 
 Operating
          revenues
          increased by $2 million, or 1.5%, in the third quarter of 2005 compared
          with the
          third quarter of 2004. Higher revenues in the third quarter of 2005 primarily
          resulted from increased retail generation sales revenues of $6 million
          and a $2
          million increase in rental revenues, partially offset by a $6 million decrease
          in wholesale sales to FES. Retail generation sales increased as a result
          of
          increased KWH sales to residential (7.6%) and commercial (4.0%) customers,
          due
          to warmer weather in Penn's service area, and a 19.8% KWH sales increase
          to
          industrial customers, primarily within the steel sector.
 
 Revenues
          from
          distribution deliveries in the third quarter of 2005 increased slightly
          from the
          third quarter of 2004, as lower unit prices partially offset a 10.2% increase
          in
          KWH sales. The lower unit prices were primarily attributable to changes
          in
          Penn's CTC rate schedules in April 2005 as a result of the annual CTC
          reconciliation. Increased revenues from distribution deliveries to residential
          ($0.3 million) and industrial ($0.8 million) customers were offset by a
          $1
          million decrease in revenues from commercial customers.
 
 Operating
          revenues
          decreased by $6 million in the first nine months of 2005 compared with
          the same
          period of 2004. The lower operating revenues reflected a $24 million decrease
          in
          wholesale sales to FES, partially offset by higher retail sales of $14
          million.
          Higher retail electric generation revenues of $14 million resulted from
          increased KWH sales to all sectors (Residential - 8.0%, Commercial - 5.6%
          and
          Industrial - 1.5%) and higher unit prices for commercial and industrial
          customers.
  In
          the first nine
          months of 2005, revenues from distribution deliveries increased by $0.3
          million
          compared to the same period of 2004. An increase in total KWH deliveries
          of 5.0%
          was offset by lower unit prices, reflecting the changes in Penn's CTC rates
          discussed above. Increased revenues from distribution deliveries to residential
          customers of $4 million were partially offset by lower revenues from commercial
          ($1 million) and industrial ($2 million) customers.
 
 Changes
          in
          kilowatt-hour sales by customer class in the three months and nine months
          ended
          September 30, 2005 from the corresponding periods of 2004 are summarized
          in the
          following table:
 **Three**
              
              **Nine****Changes
                  in KWH Sales**
              
              **Months**
              
              **Months****Increase
                  (Decrease)**Electric
                  Generation:Retail
              
              
              10.2
              %
              
              5.0
              %Wholesale
              
              
              (1.4
              )%
              
              (5.5
              )%**Total
                  Electric Generation Sales**
              
              
              3.1
              **%**
              
              (1.4
              **)%**Distribution
                  Deliveries:Residential
              
              
              7.6
              %
              
              8.0
              %Commercial
              
              
              4.0
              %
              
              5.6
              %Industrial
              
              
              19.8
              %
              
              1.5
              %**Total
                  Distribution Deliveries**
              
              
              10.2
              **%**
              
              5.0
              **%**
 
 
 119
 *Operating
          Expenses and Taxes*
  Total
          operating
          expenses and taxes decreased by $1 million in the third quarter and $2
          million
          in the first nine months of 2005 from the same periods of 2004. The following
          table presents changes from the prior year by expense
          category.
 **Three**
              
              **Nine****Operating
                  Expenses and Taxes - Changes**
              
              **Months**
              
              **Months*****(In
                  millions)*****Increase
                  (Decrease)**Fuel
                  costs
              
              $
              -
              
              $
              (1
              )Purchased
                  power costs
              
              
              (2
              )
              
              (4
              )Nuclear
                  operating costs
              
              
              (3
              )
              
              1Other
                  operating costs
              
              
              3
              
              
              3General
                  taxes
              
              
              -
              
              
              2Income
                  taxes
              
              
              1
              
              
              (3
              )**Net
                  decrease in operating expenses and taxes**
              
              $
              (1
              )
              $
              (2
              )
  The
          decrease in purchased power
          costs in the three months and nine months ended September 30, 2005 resulted
          from
          lower unit prices for power. Nuclear operating costs were lower in the
          third
          quarter of 2005, reflecting a decrease in labor and postretirement benefit
          expenses from the third quarter of 2004. Other operating costs were higher
          in
          the three months and nine months ended September 30, 2005 as the result
          of
          increased transmission related expenses associated with MISO's energy market
          that began on April 1, 2005.
 
 *Other
          Income*
 
 Other
          income (net
          of income taxes) decreased slightly in the third quarter and by $2 million
          in
          the first nine months of 2005, compared with the same periods in 2004.
          The
          decrease in the nine month period reflects liabilities recognized in the
          first
          quarter of 2005 related to the W. H. Sammis Plant settlement (see Outlook
          -
          Environmental Matters).
 
 *Net
          Interest
          Charges*
 
 Net
          interest
          charges decreased by $1 million in the nine months ended September 30,
          2005 from
          the corresponding period last year, reflecting redemptions of $40 million
          principal amount of debt securities since October 1, 2004.
 
 **Capital
          Resources and Liquidity**
 
 Penn’s
          cash
          requirements for operating expenses, construction expenditures, scheduled
          debt
          maturities and preferred stock redemptions are expected to be met 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*
 
 As
          of September 30,
          2005, Penn had $24,000 of cash and cash equivalents, compared with $38,000
          as of
          December 31, 2004. The major changes in these balances are summarized
          below.
 
 *Cash
          Flows From
          Operating Activities*
 
 Net
          cash provided
          from operating activities in the three months and nine months ended September
          30, 2005, compared with the corresponding 2004 periods, was as
          follows:
 
 **Three
                  Months Ended**
              
              **Nine
                  Months Ended****September
                  30,**
              
              **September
                  30,****Operating
                  Cash Flows**
              
              **2005**
              
              **2004**
              
              **2005**
              
              **2004*****(In
                  millions)***Cash
                  earnings(1)
              
              $
              40
              
              $
              34
              
              $
              101
              
              $
              108Pension
                  trust
                  contribution(2)
              
              
              -
              
              
              (8
              )
              
              -
              
              
              (8
              )Working
                  capital and other
              
              
              -
              
              
              10
              
              
              (5
              )
              
              5Total
                  cash
                  flows from operating activities
              
              $
              40
              
              $
              36
              
              $
              96
              
              $
              105(1)Cash
                  earnings is a non-GAAP measure (see reconciliation below).
                (2)Pension
                  trust contribution net of $5 million of income tax
                  benefits.
   120
 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. The following table reconciles cash earnings
          with net income.
 **Three
                  Months Ended**
              
              **Nine
                  Months Ended****September
                  30,**
              
              **September
                  30,****Reconciliation
                  of Cash Earnings**
              
              **2005**
              
              **2004**
              
              **2005**
              
              **2004*****(In
                  millions)***Net
                  income
                  (GAAP)
              
              $
              23
              
              $
              20
              
              $
              54
              
              $
              58Non-cash
                  charges (credits):Provision
                  for
                  depreciation
              
              
              4
              
              
              4
              
              
              11
              
              
              10Amortization
                  of regulatory assets
              
              
              10
              
              
              10
              
              
              29
              
              
              30Nuclear
                  fuel
                  and other amortization
              
              
              5
              
              
              4
              
              
              13
              
              
              14Deferred
                  income taxes and investment tax credits, net
              
              
              (3
              )
              
              (5
              )
              
              (8
              )
              
              (8
              )Other
                  non-cash items
              
              
              1
              
              
              1
              
              
              2
              
              
              4Cash
                  earnings
                  (Non-GAAP)
              
              $
              40
              
              $
              34
              
              $
              101
              
              $
              108
  The
          $6 million
          increase in cash earnings in the third quarter of 2005 and the $7 million
          decrease in cash earnings for the first nine months of 2005, as compared
          to the
          corresponding periods of 2004, are described under “Results of Operations.” The
          $10 million change in working capital and other in the three-month period
          was
          primarily due to a $49 million change in accounts payable, partially offset
          by
          changes of $35 million in receivables, $2 million in materials and supplies,
          and
          $2 million in accrued taxes. The $10 million change in working capital
          and other
          in the nine-month period was primarily due to a $51 million change in accounts
          payable, partially offset by changes of $26 million in receivables, $3
          million
          in materials and supplies, and $10 million in accrued taxes.
 
 *Cash
          Flows From
          Financing Activities*
 
 Net
          cash used for
          financing activities totaled $11 million in the third quarter of 2005,
          compared
          with $8 million in the same period last year. The $3 million increase resulted
          primarily from the absence of a $25 million equity contribution from OE
          in the
          third quarter of 2004, partially offset by a $21 million decrease in debt
          redemptions and repayments in the third quarter of 2005.
 
 Net
          cash used for
          financing activities totaled $25 million in the nine months ended September
          30,
          2005, compared with $52 million in the same period last year. The $27 million
          decrease resulted primarily from reduced long-term debt redemptions and
          common
          stock dividend payments in the first nine months of 2005, offset by reduced
          short-term borrowings and OE's $25 million equity contribution in
          2004.
 
 On
          May 16,
          2005, Penn redeemed all 127,500 outstanding shares of 7.625% preferred
          stock at
          $102.29 per share and all 250,000 outstanding shares of 7.75% preferred
          stock at
          $100 per share, both plus accrued dividends to the date of redemption.
          The total
          par value of the preferred stock redeemed was $37.8 million.
 
 Penn
          had $590,000
          of cash and temporary investments (which included short-term notes receivable
          from associated companies) and $35 million of short-term indebtedness as
          of
          September 30, 2005. Penn has authorization from the SEC to incur short-term
          debt
          up to its charter limit of $51 million. As of October 24, 2005, Penn had
          the
          capability to issue approximately $520 million of additional FMB on the
          basis of
          property additions and retired bonds following the recently completed
          intra-system transfer of fossil generating plants (See Note 17) . Based
          upon
          applicable earnings coverage tests, Penn could issue up to $383 million
          of
          preferred stock (assuming no additional debt was issued) as of September
          30,
          2005. It is estimated that the annualized impact of the intra-system transfer
          of
          fossil generating plants will reduce the capability of Penn to issue preferred
          stock by approximately 14%. The above financing capabilities do not take
          into
          consideration changes related to the intercompany transfer of generating
          assets
          (see Note 17).
 
 On
          June 14,
          2005, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI,
          as Borrowers, entered into a syndicated $2 billion five-year revolving
          credit
          facility. Borrowings under the facility are available to each Borrower
          separately and will mature on the earlier of 364 days from the date of
          borrowing
          and the commitment termination date, as the same may be extended. Penn's
          borrowing limit under the facility is $51 million.
 
 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
          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 under these arrangements in the
          third
          quarter of 2005 was 3.50%.
   121
  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. 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. The facility was not
          drawn as
          of September 30, 2005. On July 15, 2005, the facility was renewed
          until
          June 29, 2006. The annual facility fee is 0.25% on the entire finance limit.
 
 Penn’s
          access to
          capital markets and costs of financing are dependent on the ratings of
          its
          securities and the securities of OE and FirstEnergy.
 
 On
          July 18,
          2005, Moody’s revised its rating outlook on FirstEnergy and its subsidiaries to
          positive from stable. Moody’s stated that the revision to FirstEnergy’s outlook
          resulted from steady financial improvement and steps taken by management
          to
          improve operations, including the stabilization of its nuclear operations.
          Moody’s further stated that the revision in their outlook recognized
          management’s regional strategy of focusing on its core utility businesses and
          the improvement in FirstEnergy’s credit profile stemming from the application of
          free cash flow toward debt reduction. Moody’s noted that a ratings upgrade could
          be considered if FirstEnergy continues to achieve planned improvements
          in its
          operations and balance sheet.
 
 On
          October 3,
          2005, S&P raised its corporate credit rating on FirstEnergy and the EUOC to
          'BBB' from 'BBB-'. At the same time, S&P raised the senior unsecured ratings
          at the holding company to 'BBB-' from 'BB+' and each of the EUOC by one
          notch
          above the previous rating. S&P noted that the upgrade followed the
          continuation of a good operating track record, specifically for the nuclear
          fleet through the third quarter 2005. S&P also stated that FirstEnergy’s
          rating reflects the benefits of supportive regulation, low-cost base load
          generation fleet, low-risk transmission and distribution operations and
          rate
          certainty in Ohio. FirstEnergy’s ability to consistently generate free cash
          flow, good liquidity, and an improving financial profile were also noted
          as
          strengths.
 
 *Cash
          Flows From
          Investing Activities*
 
 Net
          cash used in
          investing activities totaled $29 million in the third quarter of 2005,
          compared
          with $28 million in the third quarter of 2004. For the nine months ended
          September 30, 2005, net cash used in investing activities totaled $71 million,
          compared with $53 million in the same period last year. The $18 million
          increase
          was primarily the result of higher expenditures for property additions
          in 2005
          and reduced loan repayments from associated companies.
 
 In
          the last quarter
          of 2005, capital requirements for property additions are expected to be
          about
          $32 million. Penn also expects to contribute up to $63 million (unfunded
          liability recognized as of September 30, 2005) for nuclear decommissioning
          in
          connection with the generation asset transfers described below, and has
          additional requirements of $0.5 million to meet sinking fund requirements
          for
          long-term debt during the remainder of 2005. These cash requirements are
          expected to be satisfied from internal cash and short-term credit arrangements.
          Penn's capital spending for the period 2005-2007 is expected to be about
          $227
          million, of which approximately $87 million applies to 2005. Penn had no
          other
          material obligations as of September 30, 2005 that have not been recognized
          on
          its Consolidated Balance Sheet.
 
 On
          July 22, 2005,
          the Philadelphia Stock Exchange (Exchange) filed an application with the
          SEC for
          termination of the listing of the following three series of Penn’s cumulative
          preferred stock, $100 par value, as such series no longer met the Exchange’s
          technical listing requirements regarding the number of outstanding shares
          and
          the number of holders: 4.24% Series, 4.25% Series and 4.64% Series. On
          August
          17, 2005, the SEC granted the Exchange's application for delisting effective
          August 18, 2005.
 
 **Equity
          Price Risk**
  Included
          in Penn’s
          nuclear decommissioning trust investments are marketable equity securities
          carried at their market value of approximately $60 million and $57 million
          as of
          September 30, 2005 and December 31, 2004, respectively. A hypothetical
          10%
          decrease in prices quoted by stock exchanges would result in a $6 million
          reduction in fair value as of September 30, 2005. ****
 
 **FirstEnergy
          Intra-System Generation Asset Transfers**
 
 On
          May 13,
          2005, Penn entered into an agreement to transfer its ownership interests
          in its
          nuclear and fossil generating facilities to NGC and FGCO, respectively.
 122
  On
          October 24,
          2005, Penn completed the transfer of fossil generation assets to FGCO.
          Penn
          currently expects to complete the transfer of nuclear generation assets
          to NGC
          through a spin-off by way of dividend before the end of 2005. Consummation
          of
          the nuclear transfer remains subject to necessary regulatory approvals.
 
 These
          transactions
          are being undertaken in connection with Penn’s restructuring plan that was
          approved by the PPUC under applicable Pennsylvania electric utility
          restructuring legislation. Consistent with the restructuring plan, Penn’s
          generation assets were required to be separated from the regulated delivery
          business through transfers to a separate corporate entity. FENOC currently
          operates and maintains the nuclear generation assets to be transferred.
          FGCO, as
          lessee under a Master Facility Lease, leased, operated and maintained the
          non-nuclear generation assets that it now owns. The transactions will
          essentially complete the divestitures contemplated by the restructuring
          plan by
          transferring the ownership interests to NGC and FGCO, respectively, without
          impacting the operation of the plants.
 
 See
          Note 17 to the
          consolidated financial statements for disclosure of Penn's assets held
          for sale
          as of September 30, 2005.
 
 **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 $48 million and $18
          million
          as of September 30, 2005 and December 31, 2004, respectively, and
          are
          included in Noncurrent Liabilities on the Consolidated Balance
          Sheets.
 
 In
          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 is recommending that the Request for Proposal
          process cover the period of January 1, 2007 through May 31,
          2008.
          Under Pennsylvania's electric competition law, Penn is required to secure
          generation supply for customers who do not choose alternative suppliers
          for
          their electricity.
 
 See
          Note 14 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.
 
 **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.
 
 FirstEnergy
          plans
          to issue a report regarding its response to air emission requirements.
          FirstEnergy expects to complete the report by December 1,
          2005.
 
 *National
          Ambient Air Quality Standards*
  In
          July 1997, the
          EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS
          for fine
          particulate matter. On March 10, 2005, the EPA finalized the "Clean
          Air
          Interstate Rule" covering a total of 28 states (including 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
          nonattainment 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 ),
          in all cases
          from the 2003 levels. Penn's Ohio and Pennsylvania fossil-fired generation
          facilities will be subject to the caps on SO 2 and 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 Penn operates affected facilities.
 123
 *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. On March 14, 2005,
            the EPA
            finalized the "Clean Air Mercury Rule," 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 Clean Air Mercury rule have been challenged in the United States
            Court
            of Appeals for the District of Columbia. Future cost of compliance
            with
            these regulations 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, which is in
            the form of
            a Consent Decree, was approved by the Court on July 11, 2005,
            requires OE
            and Penn to reduce NO x and SO 2 emission
            at W. H.
            Sammis Plant and other coal-fired plants through the installation of
            pollution
            control devices. Capital expenditures necessary to meet those requirements
            are
            currently estimated to be $1.5 billion (the primary portion of which
            is expected
            to be spent in the 2008 to 2011 time period). 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,
            of
            which Penn's share was $0.7 million. Results for the first quarter of
            2005
            included the $0.7 million penalty payable by Penn and a $0.8 million
            liability
            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 (Protocol), to address global warming by reducing
            the amount
            of man-made greenhouse gases emitted by developed countries by 5.2% from
            1990
            levels between 2008 and 2012. The United States signed the 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 greenhouse
            gas
            intensity - the ratio of emissions to economic output - by 18 percent
            through
            2012. The Energy Policy Act of 2005 established a Committee on Climate
            Change
            Technology to coordinate federal climate change activities and promote
            the
            development and deployment of GHG reducing technologies.
 
 Penn
            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 KWH
            of electricity generated by Penn is lower than many regional competitors
            due to
            Penn's diversified generation sources which include low or non-CO 2 emitting gas-fired
            and nuclear generators.
 
 See
            Note 13(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 Penn's normal business operations pending against Penn. The
            other
            material items not otherwise discussed above are described below.
 
 124
 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 website (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 also is proceeding with
          the
          implementation of the recommendations regarding enhancements to regional
          reliability 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, and therefore FirstEnergy has not accrued a liability as of
          September 30, 2005 for any expenditures in excess of those actually
          incurred through that date. 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 that
          could
          require additional, material expenditures. Finally, the PUCO is continuing
          to
          review FirstEnergy’s filing that addressed upgrades to control room computer
          hardware and software and enhancements to the training of control room
          operators, before determining the next steps, if any, in the
          proceeding.
 
 One
          complaint was
          filed on August 25, 2004 against FirstEnergy in the New York State Supreme
          Court. In this case, several plaintiffs in the New York City metropolitan
          area
          allege that they suffered damages as a result of the August 14,
          2003 power
          outages. None of the plaintiffs are customers of any FirstEnergy affiliate.
          FirstEnergy's motion to dismiss the case was granted on September 26,
          2005.
          Additionally, FirstEnergy Corp. was named in a complaint filed in Michigan
          State
          Court by an individual who is not a customer of any FirstEnergy company.
          A
          responsive pleading to this matter is not due until on or about December
          1,
          2005. No estimate of potential liability has been undertaken in this matter.
 
 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.
 
 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 effective corrective action. FENOC operates the Perry Nuclear Power
          Plant,
          in which Penn currently has a 5.24% interest (however, see Note 17 regarding
          FirstEnergy’s pending intra-system generation asset transfers, which will
          include owned portions of the 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.
 125
 On
          May 26,
          2005, the NRC held a public meeting to discuss its oversight of the Perry
          Plant.
          While the NRC stated that the plant continued to operate safely, the NRC
          also
          stated that the overall performance had not substantially improved since
          the
          heightened inspection was initiated. The NRC reiterated this conclusion
          in its
          mid-year assessment letter dated August 30, 2005. On September 28,
          2005, the NRC sent a CAL to FENOC describing commitments that FENOC had
          made to
          improve the performance of Perry 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. 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. As a result, these
          matters could have a material adverse effect on FirstEnergy's or its
          subsidiaries' financial condition, results of operations and cash
          flows.
 
 See
          Note 13(C) to
          the consolidated financial statements for further details and a complete
          discussion of other legal proceedings.
 
 **New
          Accounting Standards and Interpretations**
 
 *EITF
          Issue
          04-13, "Accounting for Purchases and Sales of Inventory with the Same
          Counterparty"*
  In
          September 2005,
          the EITF reached a final consensus on Issue 04-13 concluding that two or
          more
          legally separate exchange transactions with the same counterparty should
          be
          combined and considered as a single arrangement for purposes of applying
          APB 29,
          when the transactions were entered into "in contemplation" of one another.
          If
          two transactions are combined and considered a single arrangement, the
          EITF
          reached a consensus that an exchange of inventory should be accounted for
          at
          fair value. Although electric power is not capable of being held in inventory,
          there is no substantive conceptual distinction between exchanges involving
          power
          and other storable inventory. Therefore, Penn will adopt this EITF effective
          for
          new arrangements entered into, or modifications or renewals of existing
          arrangements, in interim or annual periods beginning after March 15, 2006.
 
 *FIN
          47,
“Accounting for Conditional Asset Retirement Obligations - an interpretation
          of
          FASB Statement No. 143”*
 
 On
          March 30,
          2005, the FASB issued FIN 47 to clarify the scope and timing of liability
          recognition for conditional asset retirement obligations. Under this
          interpretation, companies are required to recognize a liability for the
          fair
          value of an asset retirement obligation that is conditional on a future
          event,
          if the fair value of the liability can be reasonably estimated. In instances
          where there is insufficient information to estimate the liability, the
          obligation is to be recognized in the first period in which sufficient
          information becomes available to estimate its fair value. If the fair value
          cannot be reasonably estimated, that fact and the reasons why must be disclosed.
          This Interpretation is effective for Penn in the fourth quarter of 2005.
          Penn is
          currently evaluating the effect this Interpretation will have on its financial
          statements.
 
 *SFAS
                    154
                    - “Accounting Changes and Error Corrections - a replacement of APB
                    Opinion
                    No. 20 and FASB Statement No.
                    3”*
 
 In
          May 2005, the
          FASB issued SFAS 154 to change the requirements for accounting and reporting
          a
          change in accounting principle. It applies to all voluntary changes in
          accounting principle and to changes required by an accounting pronouncement
          when
          that pronouncement does not include specific transition provisions. This
          Statement requires retrospective application to prior periods’ financial
          statements of changes in accounting principle, unless it is impracticable
          to
          determine either the period-specific effects or the cumulative effect of
          the
          change. In those instances, this Statement requires that the new accounting
          principle be applied to the balances of assets and liabilities as of the
          beginning of the earliest period for which retrospective application is
          practicable and that a corresponding adjustment be made to the opening
          balance
          of retained earnings (or other appropriate components of equity or net
          assets in
          the statement of financial position) for that period rather than being
          reported
          in the Consolidated Statements of Income. This Statement also requires
          that a
          change in depreciation, amortization, or depletion method for long-lived,
          nonfinancial assets be accounted for as a change in accounting estimate
          affected
          by a change in accounting principle. The provisions of this Statement are
          effective for accounting changes and corrections of errors made in fiscal
          years
          beginning after December 15, 2005. Penn will adopt this Statement
          effective
          January 1, 2006.
 
 *SFAS
                    153,
                    “Exchanges of Nonmonetary Assets - an amendment of APB Opinion
                    No.
                    29”*
  In
          December 2004,
          the FASB issued SFAS 153 amending APB 29, which was based on the principle
          that
          nonmonetary assets should be measured based on the fair value of the assets
          exchanged. The guidance in APB 29 included certain exceptions to that principle.
          SFAS 153 eliminates the exception from fair value measurement for nonmonetary
          exchanges of similar productive assets and replaces it with an exception
          for
          exchanges that do not have commercial substance. This Statement specifies
          that a
          nonmonetary exchange has commercial substance if the future cash flows
          of the
          entity are expected to change significantly as a result of the exchange.
          The
          provisions of this Statement are effective January 1, 2006 for Penn.
          This
          FSP is not expected to have a material impact on Penn's financial
          statements.
  126
  *SFAS
          151,
“Inventory Costs - an amendment of ARB No. 43, Chapter 4”*
 
 In
          November 2004,
          the FASB issued SFAS 151 to clarify the accounting for abnormal amounts
          of idle
          facility expense, freight, handling costs and wasted material (spoilage).
          Previous guidance stated that in some circumstances these costs may be
“so
          abnormal” that they would require treatment as current period costs. SFAS 151
          requires abnormal amounts for these items to always be recorded as current
          period costs. In addition, this Statement requires that allocation of fixed
          production overheads to the cost of conversion be based on the normal capacity
          of the production facilities. The provisions of this statement are effective
          for
          inventory costs incurred by Penn beginning January 1, 2006. Penn
          is
          currently evaluating this Standard and does not expect it to have a material
          impact on the financial statements.
 
 *FSP
          FAS 115-1,
          "The Meaning of Other-Than-Temporary Impairment and its Application to
          Certain
          Investments"*
 
 In
          September 2005,
          the FASB finalized and renamed EITF 03-1 and 03-1-a to FSP FAS 115-1. FSP
          FAS
          115-1 will (1) supersede Issue 03-1 and EITF topic No. D-44, "Recognition
          of
          Other Than Temporary Impairment upon the Planned Sale of a Security Whose
          Cost
          Exceeds Fair Value," (2) clarify that an investor should recognize an impairment
          loss no later than when the impairment is deemed other than temporary,
          even if a
          decision to sell has not been made, and (3) be effective for
          other-than-temporary impairment and analyses conducted in periods beginning
          after September 15, 2005. The FASB expects to issue this FSP in
          the fourth
          quarter of 2005, which would require prospective application with an effective
          date for reporting periods beginning after December 15, 2005. Penn is currently
          evaluating this FSP and any impact on its investments.
 127
 **JERSEY
                        CENTRAL POWER & LIGHT COMPANY****CONSOLIDATED
                        STATEMENTS OF INCOME AND COMPREHENSIVE INCOME****(Unaudited)****Three
                        Months Ended**
                    
                    **Nine
                        Months Ended****September
                        30,**
                    
                    **September
                        30,****2005**
                    
                    **2004**
                    
                    **2005**
                    
                    **2004*****(In
                        thousands)*****STATEMENTS
                        OF INCOME****OPERATING
                        REVENUES**
                    
                    $
                    900,247
                    
                    $
                    706,613
                    
                    $
                    2,024,630
                    
                    $
                    1,754,402**OPERATING
                        EXPENSES AND TAXES:**Purchased
                        power
                    
                    
                    517,212
                    
                    
                    387,282
                    
                    
                    1,115,737
                    
                    
                    943,757Other
                        operating costs
                    
                    
                    112,690
                    
                    
                    91,516
                    
                    
                    293,996
                    
                    
                    259,176Provision
                        for
                        depreciation
                    
                    
                    19,659
                    
                    
                    18,435
                    
                    
                    59,721
                    
                    
                    56,603Amortization
                        of regulatory assets
                    
                    
                    84,388
                    
                    
                    84,271
                    
                    
                    223,012
                    
                    
                    216,705Deferral
                        of
                        new regulatory assets
                    
                    
                    -
                    
                    
                    -
                    
                    
                    (27,765
                    )
                    
                    -General
                        taxes
                    
                    
                    19,538
                    
                    
                    17,901
                    
                    
                    49,802
                    
                    
                    48,571Income
                        taxes
                    
                    
                    55,729
                    
                    
                    35,099
                    
                    
                    110,578
                    
                    
                    70,555Total
                        operating expenses and taxes
                    
                    
                    809,216
                    
                    
                    634,504
                    
                    
                    1,825,081
                    
                    
                    1,595,367**OPERATING
                        INCOME**
                    
                    
                    91,031
                    
                    
                    72,109
                    
                    
                    199,549
                    
                    
                    159,035**OTHER
                        INCOME (net of income taxes)**
                    
                    
                    3,014
                    
                    
                    1,996
                    
                    
                    3,331
                    
                    
                    4,603**NET
                        INTEREST CHARGES:**Interest
                        on
                        long-term debt
                    
                    
                    18,162
                    
                    
                    21,709
                    
                    
                    56,843
                    
                    
                    62,240Allowance
                        for
                        borrowed funds used during construction
                    
                    
                    (497
                    )
                    
                    (169
                    )
                    
                    (1,337
                    )
                    
                    (440
                    )Deferred
                        interest
                    
                    
                    (1,069
                    )
                    
                    (871
                    )
                    
                    (2,896
                    )
                    
                    (2,685
                    )Other
                        interest expense
                    
                    
                    2,283
                    
                    
                    1,105
                    
                    
                    5,262
                    
                    
                    1,958Net
                        interest
                        charges
                    
                    
                    18,879
                    
                    
                    21,774
                    
                    
                    57,872
                    
                    
                    61,073**NET
                        INCOME**
                    
                    
                    75,166
                    
                    
                    52,331
                    
                    
                    145,008
                    
                    
                    102,565**PREFERRED
                        STOCK DIVIDEND REQUIREMENTS**
                    
                    
                    125
                    
                    
                    125
                    
                    
                    375
                    
                    
                    375**EARNINGS
                        ON COMMON STOCK**
                    
                    $
                    75,041
                    
                    $
                    52,206
                    
                    $
                    144,633
                    
                    $
                    102,190**STATEMENTS
                        OF COMPREHENSIVE INCOME****NET
                        INCOME**
                    
                    $
                    75,166
                    
                    $
                    52,331
                    
                    $
                    145,008
                    
                    $
                    102,565**OTHER
                        COMPREHENSIVE INCOME:**Unrealized
                        gain on derivative hedges
                    
                    
                    102
                    
                    
                    173
                    
                    
                    208
                    
                    
                    217Unrealized
                        loss on available for sale securities
                    
                    
                    -
                    
                    
                    -
                    
                    
                    -
                    
                    
                    (8
                    )Other
                        comprehensive income
                    
                    
                    102
                    
                    
                    173
                    
                    
                    208
                    
                    
                    209Income
                        tax
                        expense (benefit) related to other comprehensive income
                    
                    
                    42
                    
                    
                    (1,542
                    )
                    
                    85
                    
                    
                    (1,546
                    )Other
                        comprehensive income, net of tax
                    
                    
                    60
                    
                    
                    1,715
                    
                    
                    123
                    
                    
                    1,755**TOTAL
                        COMPREHENSIVE INCOME**
                    
                    $
                    75,226
                    
                    $
                    54,046
                    
                    $
                    145,131
                    
                    $
                    104,320The
                        preceding
                        Notes to Consolidated Financial Statements as they relate
                        to Jersey
                        Central Power & Light Company are an integral part of these
                        statements.
   128
 
 **JERSEY
                          CENTRAL POWER & LIGHT COMPANY****CONSOLIDATED
                          BALANCE SHEETS****(Unaudited)****September
                          30,**
                      
                      **December
                          31,****2005**
                      
                      **2004*****(In
                          thousands)*****ASSETS****UTILITY
                          PLANT:**In
                          service
                      
                      $
                      3,840,213
                      
                      $
                      3,730,767Less
                          -
                          Accumulated provision for depreciation
                      
                      
                      1,424,801
                      
                      
                      1,380,7752,415,412
                      
                      
                      2,349,992Construction
                          work in progress
                      
                      
                      85,335
                      
                      
                      75,0122,500,747
                      
                      
                      2,425,004**OTHER
                          PROPERTY AND INVESTMENTS:**Nuclear
                          plant
                          decommissioning trusts
                      
                      
                      143,937
                      
                      
                      138,205Nuclear
                          fuel
                          disposal trust
                      
                      
                      164,070
                      
                      
                      159,696Long-term
                          notes receivable from associated companies
                      
                      
                      19,751
                      
                      
                      20,436Other
                      
                      
                      16,597
                      
                      
                      19,379344,355
                      
                      
                      337,716**CURRENT
                          ASSETS:**Cash
                          and cash
                          equivalents
                      
                      
                      571
                      
                      
                      162Receivables
                          -Customers
                          (less accumulated provisions of $4,264,000 and $3,881,000,respectively,
                          for uncollectible accounts)
                      
                      
                      313,730
                      
                      
                      201,415Associated
                          companies
                      
                      
                      1,171
                      
                      
                      86,531Other
                          (less
                          accumulated provisions of $239,000 and $162,000,respectively,
                          for uncollectible accounts)
                      
                      
                      38,569
                      
                      
                      39,898Materials
                          and
                          supplies, at average cost
                      
                      
                      1,863
                      
                      
                      2,435Prepayments
                          and other
                      
                      
                      33,254
                      
                      
                      31,489389,158
                      
                      
                      361,930**DEFERRED
                          CHARGES:**Regulatory
                          assets
                      
                      
                      2,310,532
                      
                      
                      2,176,520Goodwill
                      
                      
                      1,983,699
                      
                      
                      1,985,036Other
                      
                      
                      2,850
                      
                      
                      4,9784,297,081
                      
                      
                      4,166,534$
                      7,531,341
                      
                      $
                      7,291,184**CAPITALIZATION
                          AND LIABILITIES****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
                      
                      
                      3,014,600
                      
                      
                      3,013,912Accumulated
                          other comprehensive loss
                      
                      
                      (55,411
                      )
                      
                      (55,534
                      )Retained
                          earnings
                      
                      
                      104,904
                      
                      
                      43,271Total
                          common
                          stockholder's equity
                      
                      
                      3,217,806
                      
                      
                      3,155,362Preferred
                          stock
                      
                      
                      12,649
                      
                      
                      12,649Long-term
                          debt
                          and other long-term obligations
                      
                      
                      1,017,478
                      
                      
                      1,238,9844,247,933
                      
                      
                      4,406,995**CURRENT
                          LIABILITIES:**Currently
                          payable long-term debt
                      
                      
                      167,045
                      
                      
                      16,866Notes
                          payable
                          -Associated
                          companies
                      
                      
                      114,932
                      
                      
                      248,532Accounts
                          payable -Associated
                          companies
                      
                      
                      8,968
                      
                      
                      20,605Other
                      
                      
                      162,583
                      
                      
                      124,733Accrued
                          taxes
                      
                      
                      78,342
                      
                      
                      2,626Accrued
                          interest
                      
                      
                      23,535
                      
                      
                      10,359Other
                      
                      
                      152,638
                      
                      
                      65,130708,043
                      
                      
                      488,851**NONCURRENT
                          LIABILITIES:**Power
                          purchase
                          contract loss liability
                      
                      
                      1,410,659
                      
                      
                      1,268,478Accumulated
                          deferred income taxes
                      
                      
                      670,514
                      
                      
                      645,741Nuclear
                          fuel
                          disposal costs
                      
                      
                      173,591
                      
                      
                      169,884Asset
                          retirement obligation
                      
                      
                      76,002
                      
                      
                      72,655Retirement
                          benefits
                      
                      
                      100,567
                      
                      
                      103,036Other
                      
                      
                      144,032
                      
                      
                      135,5442,575,365
                      
                      
                      2,395,338**COMMITMENTS
                          AND CONTINGENCIES (Note 13)**$
                      7,531,341
                      
                      $
                      7,291,184The
                          preceding
                          Notes to Consolidated Financial Statements as they relate
                          to Jersey
                          Central Power & Light Company are anintegral
                          part
                          of these blance sheets.
   129
  **JERSEY
                        CENTRAL POWER & LIGHT COMPANY****CONSOLIDATED
                        STATEMENTS OF CASH FLOWS****(Unaudited)****Three
                        Months Ended**
                    
                    **Nine
                        Months Ended****September
                        30,**
                    
                    **September
                        30,****2005**
                    
                    **2004**
                    
                    **2005**
                    
                    **2004*****(In
                        thousands)*****CASH
                        FLOWS FROM OPERATING ACTIVITIES:**Net
                        income
                    
                    $
                    75,166
                    
                    $
                    52,331
                    
                    $
                    145,008
                    
                    $
                    102,565Adjustments
                        to reconcile net income to net cash fromoperating
                        activities -Provision
                        for
                        depreciation
                    
                    
                    19,659
                    
                    
                    18,436
                    
                    
                    59,721
                    
                    
                    56,603Amortization
                        of regulatory assets
                    
                    
                    84,388
                    
                    
                    84,269
                    
                    
                    223,012
                    
                    
                    216,704Deferral
                        of
                        new regulatory assets
                    
                    
                    -
                    
                    
                    -
                    
                    
                    (27,765
                    )
                    
                    -Deferred
                        purchased power and other costs
                    
                    
                    (42,381
                    )
                    
                    (77,162
                    )
                    
                    (168,646
                    )
                    
                    (155,552
                    )Deferred
                        income taxes and investment tax credits, net
                    
                    
                    (11,222
                    )
                    
                    6,165
                    
                    
                    5,204
                    
                    
                    (13,582
                    )Accrued
                        retirement benefit obligation
                    
                    
                    813
                    
                    
                    2,888
                    
                    
                    (2,468
                    )
                    
                    (5,880
                    )Accrued
                        compensation, net
                    
                    
                    671
                    
                    
                    1,547
                    
                    
                    (4,077
                    )
                    
                    731NUG
                        power
                        contract restructuring
                    
                    
                    -
                    
                    
                    -
                    
                    
                    -
                    
                    
                    52,800Cash
                        collateral from suppliers
                    
                    
                    76,978
                    
                    
                    -
                    
                    
                    76,978
                    
                    
                    -Pension
                        trust
                        contribution
                    
                    
                    -
                    
                    
                    (62,499
                    )
                    
                    -
                    
                    
                    (62,499
                    )Decrease
                        (increase) in operating assets -Receivables
                    
                    
                    (39,897
                    )
                    
                    (34,749
                    )
                    
                    (25,626
                    )
                    
                    (26,906
                    )Materials
                        and
                        supplies
                    
                    
                    395
                    
                    
                    64
                    
                    
                    572
                    
                    
                    411Prepayments
                        and other current assets
                    
                    
                    64,761
                    
                    
                    34,664
                    
                    
                    (1,764
                    )
                    
                    (5,040
                    )Increase
                        (decrease) in operating liabilities -Accounts
                        payable
                    
                    
                    (5,873
                    )
                    
                    57,485
                    
                    
                    26,214
                    
                    
                    58,430Accrued
                        taxes
                    
                    
                    18,498
                    
                    
                    (27,924
                    )
                    
                    75,716
                    
                    
                    35,844Accrued
                        interest
                    
                    
                    13,765
                    
                    
                    16,709
                    
                    
                    13,176
                    
                    
                    11,481Other
                    
                    
                    6,928
                    
                    
                    27,603
                    
                    
                    23,982
                    
                    
                    8,539Net
                        cash
                        provided from operating activities
                    
                    
                    262,649
                    
                    
                    99,827
                    
                    
                    419,237
                    
                    
                    274,649**CASH
                        FLOWS FROM FINANCING ACTIVITIES:**New
                        Financing-Long-term
                        debt
                    
                    
                    -
                    
                    
                    -
                    
                    
                    -
                    
                    
                    300,000Redemptions
                        and Repayments-Long-term
                        debt
                    
                    
                    (4,321
                    )
                    
                    (7,082
                    )
                    
                    (67,648
                    )
                    
                    (304,150
                    )Short-term
                        borrowings, net
                    
                    
                    (164,172
                    )
                    
                    (456
                    )
                    
                    (133,600
                    )
                    
                    (72,648
                    )Dividend
                        Payments-Common
                        stock
                    
                    
                    (43,000
                    )
                    
                    (40,000
                    )
                    
                    (83,000
                    )
                    
                    (60,000
                    )Preferred
                        stock
                    
                    
                    (125
                    )
                    
                    (125
                    )
                    
                    (375
                    )
                    
                    (375
                    )Net
                        cash used
                        for financing activities
                    
                    
                    (211,618
                    )
                    
                    (47,663
                    )
                    
                    (284,623
                    )
                    
                    (137,173
                    )**CASH
                        FLOWS FROM INVESTING ACTIVITIES:**Property
                        additions
                    
                    
                    (50,837
                    )
                    
                    (52,507
                    )
                    
                    (133,498
                    )
                    
                    (135,932
                    )Loan
                        repayments from (loans to) associated companies, net
                    
                    
                    15
                    
                    
                    (711
                    )
                    
                    685
                    
                    
                    (1,122
                    )Other
                    
                    
                    (50
                    )
                    
                    1,049
                    
                    
                    (1,392
                    )
                    
                    (416
                    )Net
                        cash used
                        for investing activities
                    
                    
                    (50,872
                    )
                    
                    (52,169
                    )
                    
                    (134,205
                    )
                    
                    (137,470
                    )Net
                        increase
                        (decrease) in cash and cash equivalents
                    
                    
                    159
                    
                    
                    (5
                    )
                    
                    409
                    
                    
                    6Cash
                        and cash
                        equivalents at beginning of period
                    
                    
                    412
                    
                    
                    282
                    
                    
                    162
                    
                    
                    271Cash
                        and cash
                        equivalents at end of period
                    
                    $
                    571
                    
                    $
                    277
                    
                    $
                    571
                    
                    $
                    277The
                        preceding
                        Notes to Consolidated Financial Statements as they relate
                        to Jersey
                        Central Power & Light Company are an integral  part of these
                        statements.
    130
 ***Report
              of Independent Registered Public Accounting Firm***
 
 
 
 
 
 
 
 
 
 To
              the Stockholders
              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, 2005, and the related
              consolidated statements of income and comprehensive income and cash
              flows for
              each of the three-month and nine-month periods ended September 30,
              2005 and
              2004. 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
              previously
              audited, in accordance with the standards of the Public Company Accounting
              Oversight Board (United States), the consolidated balance sheet as
              of
              December 31, 2004, and the related consolidated statements of
              income,
              capitalization, common stockholder’s 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,
              2004 and the effectiveness of the Company’s internal control over financial
              reporting as of December 31, 2004; 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 9 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 March 7, 2005, 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 information as of December 31,
              2004, is fairly stated in all material respects in relation to the
              consolidated
              balance sheet from which it has been derived.
 
 
 
 
 PricewaterhouseCoopers
              LLP
 Cleveland,
              Ohio
 November
              1,
              2005
 
 
 131
  **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. JCP&L has
              restructured its electric rates into unbundled service charges and
              transition
              cost recovery charges. JCP&L continues to deliver power to homes and
              businesses through its existing distribution system.
 
 **Results
              of Operations**
 
 Earnings
              on common
              stock in the third quarter of 2005 increased to $75 million from $52
              million in
              the third quarter of 2004. During the first nine months of 2005, earnings
              on
              common stock increased to $145 million compared to $102 million for
              the same
              period of 2004. The increase in earnings for both periods was primarily
              due to
              higher operating revenues partially offset by increases in purchased
              power
              costs, other operating costs and income taxes. Other operating costs
              in both
              periods of 2005 included a charge of $16 million for potential awards
              related to
              a labor arbitration decision (see note 13 - Other Legal Matters).
  Operating
              revenues
              increased $194 million or 27.4% in the third quarter and $270 million
              or 15.4%
              in the first nine months of 2005 compared with the same periods in
              2004.
              Increases in both periods were due to higher retail electric generation,
              distribution and wholesale revenues.
 
 Retail
              generation
              revenues increased by $82 million in the third quarter and $134 million
              in the
              first nine months of 2005 as compared to the previous year. Higher
              KWH sales to
              residential and commercial customers increased generation revenues
              by $45
              million in the third quarter and $81 million in the first nine months
              of 2005.
              Commercial generation revenue increased for the same periods of 2005
              by $33
              million and $54 million, respectively. The increases were attributable
              to higher
              KWH sales (residential - 14.9% and commercial - 20.3% in the third
              quarter of
              2005; residential - 15.3% and commercial - 13.4% for the first nine
              months of
              2005) primarily due to warmer weather and reduced customer shopping.
              Generation
              provided by alternative suppliers to residential and commercial customers
              as a
              percent of total sales delivered in JCP&L’s service area decreased by 6.9
              and 4.6 percentage points, respectively, in the first nine months of
              2005.
              Industrial generation revenue increased by $4 million in the third
              quarter, but
              declined $2 million in the first nine months of 2005 reflecting the
              effect of a
              25.6% KWH sales increase in the third quarter and a 9.3% decline in
              the first
              nine months of 2005.
 
 Revenues
              from
              wholesale sales increased by $49 million in the third quarter and $42
              in the
              first nine months of 2005 as compared to the previous year, principally
              due to
              increased prices in 2005. KWH sales to the wholesale sector increased
              in the
              quarter (5.5%) but declined for the first nine months (8.5%).
 
 Distribution
              revenues increased by $62 million in the third quarter and $96 million
              in the
              first nine months of 2005, as compared to the same periods of 2004,
              due to
              increased KWH deliveries to all customer sectors and higher composite
              unit
              prices, caused in part by the June 1, 2005 rate increase.
 
 Changes
              in KWH
              sales by customer class in the three months and nine months ended
              September 30, 2005 compared to the same periods of 2004 are
              summarized in
              the following table:
 **Three**
                  
                  **Nine****Changes
                      in KWH Sales**
                  
                  **Months**
                  
                  **Months****Increase
                      (Decrease)**Electric
                      Generation:Retail
                  
                  
                  17.2
                  %
                  
                  13.4
                  %Wholesale
                  
                  
                  5.5
                  %
                  
                  (8.5
                  )%**Total
                      Electric Generation Sales**
                  
                  
                  14.8
                  **%**
                  
                  8.2
                  **%**Distribution
                      Deliveries:Residential
                  
                  
                  15.6
                  %
                  
                  7.4
                  %Commercial
                  
                  
                  13.4
                  %
                  
                  6.7
                  %Industrial
                  
                  
                  5.4
                  %
                  
                  0.4
                  %**Total
                      Distribution Deliveries**
                  
                  
                  13.4
                  **%**
                  
                  6.2
                  **%**
    132
 *Operating
              Expenses and Taxes*
 
 Total
              operating
              expenses and taxes increased by $175 million in the third quarter and
              $230
              million in the first nine months of 2005 compared with the same periods
              of 2004.
              The following table presents changes from the prior year by expense
              category.
 **Three**
                  
                  **Nine****Operating
                      Expenses and Taxes - Changes**
                  
                  **Months**
                  
                  **Months*****(In
                      millions)*****Increase
                      (Decrease)**Purchased
                      power costs
                  
                  $
                  130
                  
                  $
                  172Other
                      operating costs
                  
                  
                  21
                  
                  
                  35Provision
                      for
                      depreciation
                  
                  
                  1
                  
                  
                  3Amortization
                      of regulatory assets
                  
                  
                  -
                  
                  
                  7Deferral
                      of
                      new regulatory assets
                  
                  
                  -
                  
                  
                  (28
                  )General
                      taxes
                  
                  
                  2
                  
                  
                  1Income
                      taxes
                  
                  
                  21
                  
                  
                  40**Net
                      increase in operating expenses and taxes**
                  
                  $
                  175
                  
                  $
                  230
 
 Purchased
              power
              costs increased by $130 million in the third quarter and $172 million
              in the
              first nine months of 2005 as compared to the same periods in 2004 due
              to higher
              KWH purchases to meet increased retail generation sales and, to a lesser
              extent,
              higher unit costs. Other operating costs increased $21 million in the
              third
              quarter of 2005 and $35 million in the first nine months of 2005 compared
              to the
              same periods of 2004, reflecting $16 million of expenses resulting
              from a
              JCP&L arbitration decision.
 
 Deferral
              of new
              regulatory assets decreased expenses by $28 million in the first nine
              months of
              2005, reflecting the NJBPU’s (see Regulatory Matters) approval for JCP&L to
              defer $28 million of previously incurred reliability expenses. Amortization
              of
              regulatory assets increased $7 million in the first nine months of
              2005 due to
              an increase in the level of MTC revenue recovery.
 
 **Capital
              Resources and Liquidity**
 
 JCP&L’s
              cash
              requirements for the remainder of 2005 for operating expenses, construction
              expenditures and scheduled debt maturities are expected to be met with
              cash from
              operations.
 
 *Changes
              in Cash
              Position*
 
 As
              of
              September 30, 2005, JCP&L had $571,000 of cash and cash equivalents
              compared with $162,000 as of December 31, 2004. The major sources
              for
              changes in these balances are summarized below.
 
 *Cash
              Flows From
              Operating Activities*
 
 Cash
              provided from
              operating activities in the third quarter and in the first nine months
              of 2005
              compared with the corresponding periods of 2004, were as follows:
 **Three
                      Months Ended**
                  
                  **Nine
                      Months Ended****September
                      30,**
                  
                  **September
                      30,****Operating
                      Cash Flows**
                  
                  **2005**
                  
                  **2004**
                  
                  **2005**
                  
                  **2004*****(In
                      millions)***Cash
                      earnings
                      (1)
                  
                  $
                  204
                  
                  $
                  64
                  
                  $
                  307
                  
                  $
                  177Pension
                      trust
                      contribution (2)
                  
                  
                  -
                  
                  
                  (37
                  )
                  
                  -
                  
                  
                  (37
                  )Working
                      capital and other
                  
                  
                  58
                  
                  
                  73
                  
                  
                  112
                  
                  
                  135Total
                      cash
                      flows from operating activities
                  
                  $
                  262
                  
                  $
                  100
                  
                  $
                  419
                  
                  $
                  275(1)
                      Cash earnings is a non-GAAP measure (see reconciliation
                      below).
                    (2)
                      Pension trust contribution net of $25 million of income tax
                      benefits.
 
 Cash
              earnings, as
              disclosed 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.
              The
              following table reconciles cash earnings with net income.
  133
  
 **Three
                      Months Ended**
                  
                  **Nine
                      Months Ended****September
                      30,**
                  
                  **September
                      30,****Reconciliation
                      of Cash Earnings******
                  
                  **2005**
                  
                  **2004**
                  
                  **2005**
                  
                  **2004*****(In
                      millions)***Net
                      income
                      (GAAP)
                  
                  $
                  75
                  
                  $
                  52
                  
                  $
                  145
                  
                  $
                  103Non-cash
                      charges (credits):Provision
                      for
                      depreciation
                  
                  
                  20
                  
                  
                  18
                  
                  
                  60
                  
                  
                  57Amortization
                      of regulatory assets
                  
                  
                  84
                  
                  
                  84
                  
                  
                  223
                  
                  
                  217Deferral
                      of
                      new regulatory assets
                  
                  
                  -
                  
                  
                  -
                  
                  
                  (28
                  )
                  
                  -Deferred
                      purchased power and other costs
                  
                  
                  (42
                  )
                  
                  (77
                  )
                  
                  (169
                  )
                  
                  (156
                  )Deferred
                      income taxes & investment tax credits, net
                  
                  
                  (11
                  )
                  
                  (19
                  )
                  
                  5
                  
                  
                  (39
                  )Other
                      non-cash items
                  
                  
                  78
                  
                  
                  6
                  
                  
                  71
                  
                  
                  (5
                  )Cash
                      earnings
                      (Non-GAAP)
                  
                  $
                  204
                  
                  $
                  64
                  
                  $
                  307
                  
                  $
                  177
 
 The
              $140 million
              and $130 million increases in cash earnings for the third quarter and
              the first
              nine months of 2005, respectively, are described above under “Results of
              Operations”. The $15 million and $23 million decrease for the third quarter and
              the first nine months of 2005 from working capital primarily resulted
              from a
              reduction in accounts payables partially offset by an increase in accrued
              taxes.
              In the first nine months of 2004, JCP&L received $52.8 million in connection
              with restructuring a NUG power contract.
  *Cash
              Flows From
              Financing Activities*
 
 Net
              cash used for
              financing activities was $212 million in the third quarter of 2005
              compared to
              $48 million in the third quarter of 2004. The increase resulted from
              redemptions
              of short-term debt in the third quarter of 2005. Net cash used for
              financing
              activities was $285 million for the first nine months of 2005 and $137
              million
              for the same period of 2004. The $148 million increase resulted from
              a $124
              million increase in net debt redemptions and a $23 million increase
              in common
              stock dividends to FirstEnergy.
 
 JCP&L
              had
              approximately $571,000 of cash and temporary investments and $115 million
              of
              short-term indebtedness as of September 30, 2005. JCP&L has
              authorization from the SEC to incur short-term debt up to its charter
              limit of
              $1.8 billion (including the utility money pool). JCP&L will not issue FMB
              other than as collateral for senior notes, since its senior note indentures
              prohibit (subject to certain exceptions) JCP&L from issuing any debt which
              is senior to the senior notes. As of September 30, 2005, JCP&L had the
              capability to issue $673 million of additional senior notes based upon
              FMB
              collateral. Based upon applicable earnings coverage tests and its charter,
              JCP&L could issue $976 million of preferred stock (assuming no additional
              debt was issued) as of September 30, 2005.
 
 On
              June 14,
              2005, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI,
              as Borrowers, entered into a syndicated $2 billion five-year revolving
              credit
              facility. Borrowings under the facility are available to each Borrower
              separately and mature on the earlier of 364 days from the date of borrowing
              or
              the commitment termination date, as the same may be extended. JCP&L’s
              borrowing limit under the facility is $425 million.
 
 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 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 was 3.50% in the third quarter of 2005
              and 3.03% in
              the first nine months of 2005.
 
 JCP&L’s
              access
              to capital markets and costs of financing are influenced by the ratings
              of its
              securities and the securities of FirstEnergy. The
              ratings outlook
              from S&P and Fitch on all securities is stable. Moody’s outlook on all
              securities is positive.
 
 On
              July 18,
              2005, Moody’s revised its rating outlook on FirstEnergy and its subsidiaries to
              positive from stable. Moody’s stated that the revision to FirstEnergy’s outlook
              resulted from steady financial improvement and steps taken by management
              to
              improve operations, including the stabilization of its nuclear operations.
              Moody’s further stated that the revision in their outlook recognized
              management’s regional strategy of focusing on its core utility businesses and
              the improvement in FirstEnergy’s credit profile stemming from the application of
              free cash flow toward debt reduction. Moody’s noted that a ratings upgrade could
              be considered if FirstEnergy continues to achieve planned improvements
              in its
              operations and balance sheet.
 134
 On
              October 3,
              2005, S&P raised its corporate credit rating on FirstEnergy and the EUOC to
              'BBB' from 'BBB-'. At the same time, S&P raised the senior unsecured ratings
              at the holding company to 'BBB-' from 'BB+' and each of the EUOC by
              one notch
              above the previous rating. S&P noted that the upgrade followed the
              continuation of a good operating track record, specifically for the
              nuclear
              fleet through the third quarter 2005. S&P also stated that FirstEnergy’s
              rating reflects the benefits of supportive regulation, low-cost base
              load
              generation fleet, low-risk transmission and distribution operations
              and rate
              certainty in Ohio. FirstEnergy’s ability to consistently generate free cash
              flow, good liquidity, and an improving financial profile were also
              noted as
              strengths.
 
 *Cash
              Flows From
              Investing Activities*
 
 Net
              cash used for
              investing activities was $51 million in the third quarter and $134
              million for
              the first nine months of 2005 compared to $52 million and $137 million
              for the
              same periods of 2004. JCP&L’s capital spending for the period 2005-2007 is
              expected to be about $511 million of which approximately $185 million
              applies to
              2005. In the last quarter of 2005, capital requirements for property
              additions
              and improvements are expected to be about $52 million.
 
 **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
              management oversight to risk management activities.
 
 *Commodity
              Price
              Risk*
 
 JCP&L
              is
              exposed to price risk primarily due to fluctuating electricity and
              natural gas
              prices. To manage the volatility relating to these exposures, it uses
              a variety
              of non-derivative and derivative instruments, including forward contracts,
              options and futures contracts. The derivatives are used for hedging
              purposes.
              Most of its non-hedge derivative contracts represent non-trading positions
              that
              do not qualify for hedge treatment under SFAS 133. As of September 30,
              2005, JCP&L had commodity derivative contracts with a fair value of $14
              million. A decrease of $1 million in the value of this asset was recorded
              in the
              first nine months of 2005 as a decrease in a regulatory liability,
              and
              therefore, had no impact on net income.
 
 The
              valuation of
              derivative commodity 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 valuation of derivative contracts
              as of
              September 30, 2005 are summarized by year in the following
              table:
 
 **Sources
                      of Information****-****Fair
                      Value by Contract Year**
                  
                  
                  
                  **2005(1)**
                  
                  **2006**
                  
                  **2007**
                  
                  **2008**
                  
                  **2009**
                  
                  **Thereafter**
                  
                  **Total**Prices
                      based
                      on external sources(2)
                  
                  
                  
                  
                  $
                  3
                  
                  $
                  2
                  
                  $
                  3
                  
                  $
                  -
                  
                  $
                  -
                  
                  $
                  -
                  
                  $
                  8Prices
                      based
                      on models
                  
                  
                  
                  
                  
                  -
                  
                  
                  -
                  
                  
                  -
                  
                  
                  2
                  
                  
                  2
                  
                  
                  2
                  
                  
                  6Total
                  
                  
                  
                  
                  $
                  3
                  
                  $
                  2
                  
                  $
                  3
                  
                  $
                  2
                  
                  $
                  2
                  
                  $
                  2
                  
                  $
                  14(1) For
                      the last quarter of 2005.
                    (2)Broker
                      quote sheets.
 
 JCP&L
              performs
              sensitivity analyses to estimate its exposure to the market risk of
              its
              commodity position. A hypothetical 10% adverse shift in quoted market
              prices in
              the near term on derivative instruments would not have had a material
              effect on
              its consolidated financial position or cash flows as of September 30,
              2005.
 
 *Equity
              Price
              Risk*
 
 Included
              in nuclear
              decommissioning trusts are marketable equity securities carried at
              their current
              market value of approximately $82 million and $80 million as of
              September 30, 2005 and December 31, 2004, respectively.
              A hypothetical
              10% decrease in prices quoted by stock exchanges would result in an
              $8 million
              reduction in fair value as of September 30, 2005.
   135
  **Regulatory
              Matters**
  Regulatory
              assets
              are costs which have been authorized by the NJBPU and the FERC for
              recovery from
              customers in future periods and, without such authorization, would
              have been
              charged to income when incurred. JCP&L's regulatory assets as of
              September 30, 2005 and December 31, 2004 were $2.3 billion
              and $2.2
              billion, respectively.
 
 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 MTC rates. As of
              September 30, 2005, the accumulated deferred cost balance totaled
              approximately $508 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 of the
              securitization of the July 31, 2003 deferred balance. JCP&L is in
              discussions with the NJBPU staff as a result of the stipulated settlement
              agreements (as further discussed below) which recommended that the
              NJBPU issue
              an order regarding JCP&L's application. On July 20, 2005, JCP&L
              requested the NJBPU to set a procedural schedule for this matter and
              is awaiting
              NJBPU action.
 
 The
              2003 NJBPU
              decision on JCP&L's base electric rate proceeding (the Phase I Order)
              disallowed certain regulatory assets and provided for an interim return
              on
              equity of 9.5% on JCP&L's rate base. The Phase I Order also provided for a
              Phase II proceeding in which the NJBPU would review whether JCP&L is in
              compliance with current service reliability and quality standards and
              determine
              whether the expenditures and projects undertaken by JCP&L to increase its
              system reliability are prudent and reasonable for rate recovery. Depending
              on
              its assessment of JCP&L's service reliability, the NJBPU could have
              increased JCP&L’s return on equity to 9.75% or decreased it to 9.25%. On
              August 15, 2003 and June 1, 2004, JCP&L filed with the NJBPU an
              interim motion and a supplemental and amended motion for rehearing
              and
              reconsideration of the Phase I Order, respectively. On July 7,
              2004, the
              NJPBU granted limited reconsideration and rehearing on the following
              issues: (1)
              deferred cost disallowances; (2) the capital structure including the
              rate of
              return; (3) merger savings, including amortization of costs to achieve
              merger
              savings; and (4) decommissioning costs.
 
 On
              July 16,
              2004, JCP&L filed the Phase II petition and testimony with the NJBPU,
              requesting an increase in base rates of $36 million for the recovery
              of system
              reliability costs and a 9.75% return on equity. The filing also requested
              an
              increase to the MTC deferred balance recovery of approximately $20
              million
              annually.
 
 On
              May 25,
              2005, the NJBPU approved two stipulated settlement agreements. The
              first
              stipulation between JCP&L and the NJBPU staff resolves all of the issues
              associated with JCP&L's motion for reconsideration of the Phase I Order. The
              second stipulation between JCP&L, the NJBPU staff and the Ratepayer Advocate
              resolves all of the issues associated with JCP&L's Phase II proceeding. The
              stipulated settlements provide for, among other things, the
              following:
 
 · An
              annual increase
              in distribution revenues of $23 million effective June 1, 2005,
              associated
              with the
 Phase I
              Order
              reconsideration;
 
 · An
              annual increase
              in distribution revenues of $36 million effective June 1, 2005,
              related to
              JCP&L's
 Phase II
              Petition;
 
 · An
              annual reduction
              in both rates and amortization expense of $8 million, effective June 1,
              2005, in
 anticipation
              of an
              NJBPU order regarding JCP&L's request to securitize up to $277 million of
              its deferred
 cost
              balance;
 
 · An
              increase in
              JCP&L's authorized return on common equity from 9.5% to 9.75%;
              and
 
 · A
              commitment by
              JCP&L to maintain a target level of customer service reliability with a
              reduction in
 JCP&L's
              authorized return on common equity from 9.75% to 9.5% if the target
              is not met
              for two
 consecutive
              quarters.
              The authorized return on common equity would then be restored to 9.75%
              if
              the
 target
              is met for two
              consecutive quarters.
 
 The
              Phase II
              stipulation included an agreement that the distribution revenue increase
              also
              reflects a three-year amortization of JCP&L's one-time service reliability
              improvement costs incurred in 2003-2005. This resulted in the creation
              of a
              regulatory asset associated with accelerated tree trimming and other
              reliability
              costs which were expensed in 2003 and 2004. The establishment of the
              new
              regulatory asset of approximately $28 million resulted in an increase
              to net
              income of approximately $16 million ($0.05 per share of FirstEnergy
              common
              stock) in the second quarter of 2005.
 136
 JCP&L
                sells all
                self-supplied energy (NUGs and owned generation) to the wholesale
                market with
                offsetting credits to its deferred energy balance with the exception
                of 300 MW
                from JCP&L's NUG committed supply currently being used to serve BGS
                customers pursuant to NJBPU order for the period June 1, 2005
                through May
                31, 2006. New BGS tariffs reflecting the results of a February 2005
                auction for
                the BGS supply became effective June 1, 2005. On July 1,
                2005,
                JCP&L filed its BGS procurement proposals for post transition year four.
                The
                auction is scheduled to take place in February 2006 for the annual
                supply period
                beginning June 1, 2006.
 
 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 Ratepayer Advocate filed comments on
                February 28, 2005. On March 18, 2005, JCP&L filed a response to
                those comments. A schedule for further proceedings has not yet been
                set.
 
 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. On March 29,
                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 a Special
                Reliability Master 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 Ratepayer Advocate to discuss reliability improvements.
                JCP&L
                continues to file compliance reports reflecting activities associated
                with the
                MOU and Stipulation.
 
 On
                January 31,
                2005, certain PJM transmission owners made three filings 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. Second,
                the FERC
                approved the proposed Schedule 12 rate harmonization. Third, the
                FERC accepted
                the proposed formula rate, subject to referral and hearing procedures.
                On
                September 30, 2005, the PJM transmission owners filed a request
                for
                rehearing of the May 31, 2005 order. The rate design and formula
                rate
                filings continue to be litigated before the FERC. The outcome of
                these two cases
                cannot be predicted.
 
 See
                Note 14 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 estimate 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 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, 2005, based on estimates of the total costs
                of cleanup,
                JCP&L's proportionate responsibility for such costs and the financial
                ability of other nonaffiliated 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. Included in Other Noncurrent Liabilities are
                accrued
                liabilities aggregating approximately $46.8 million as of September 30,
                2005.
 
 FirstEnergy
                plans
                to issue a report regarding its response to air emission requirements.
                FirstEnergy expects to complete the report by December 1,
                2005.
  
 137
  See
              Note 13(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 normal business operations pending against JCP&L. The other
              material items not otherwise discussed above are described below.
 
 *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. On September 8, 2004, the New Jersey Supreme Court denied
              the
              motions filed by plaintiffs and JCP&L for leave to appeal the decision of
              the Appellate Division. JCP&L has filed a motion for summary judgment.
              FirstEnergy is unable to predict the outcome of these matters and no
              liability
              has been accrued as of September 30, 2005.
 
 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 concludes, 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 website (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 also is proceeding
              with the
              implementation of the recommendations regarding enhancements to regional
              reliability 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, and therefore FirstEnergy has not accrued a liability as
              of
              September 30, 2005 for any expenditures in excess of those actually
              incurred through that date. 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
              that could
              require additional, material expenditures. Finally, the PUCO is continuing
              to
              review FirstEnergy’s filing that addressed upgrades to control room computer
              hardware and software and enhancements to the training of control room
              operators, before determining the next steps, if any, in the
              proceeding.
 138
 One
              complaint was
              filed on August 25, 2004 against FirstEnergy in the New York State
              Supreme
              Court. In this case, several plaintiffs in the New York City metropolitan
              area
              allege that they suffered damages as a result of the August 14,
              2003 power
              outages. None of the plaintiffs are customers of any FirstEnergy affiliate.
              FirstEnergy's motion to dismiss the case was granted on September 26,
              2005.
              Additionally, FirstEnergy Corp. was named in a complaint filed in Michigan
              State
              Court by an individual who is not a customer of any FirstEnergy company.
              A
              responsive pleading to this matter is not due until on or about December
              1,
              2005. No estimate of potential liability has been undertaken in this
              matter.
 
 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.
 
 *Other
              Legal
              Matters*
 
 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
              Arbitrator
              decided not to hear testimony on damages and closed the proceedings.
              On
              September 9, 2005, the Arbitrator issued an opinion to award
              approximately
              $16.1 million to the bargaining unit employees. JCP&L initiated an appeal of
              this award by filing a motion to vacate in Federal Court in New Jersey
              on
              October 18, 2005. JCP&L recognized a liability for the potential $16.1
              million award during the three months ended September 30,
              2005.
 
 See
              Note 13(C) to
              the consolidated financial statements for further details and a complete
              discussion of other legal proceedings.
 
 **New
              Accounting Standards and Interpretations**
 
 *EITF
              Issue
              04-13, "Accounting for Purchases and Sales of Inventory with the Same
              Counterparty"*
  In
              September 2005,
              the EITF reached a final consensus on Issue 04-13 concluding that two
              or more
              legally separate exchange transactions with the same counterparty should
              be
              combined and considered as a single arrangement for purposes of applying
              APB 29,
              when the transactions were entered into "in contemplation" of one another.
              If
              two transactions are combined and considered a single arrangement,
              the EITF
              reached a consensus that an exchange of inventory should be accounted
              for at
              fair value. Although electric power is not capable of being held in
              inventory,
              there is no substantive conceptual distinction between exchanges involving
              power
              and other storable inventory. Therefore, JCP&L will adopt this EITF
              effective for new arrangements entered into, or modifications or renewals
              of
              existing arrangements, in interim or annual periods beginning after
              March 15, 2006.
 
 *EITF
                        Issue No. 05-6, "Determining the Amortization Period for
                        Leasehold
                        Improvements Purchased after Lease Inception or Acquired
                        in a Business
                        Combination"*
  In
              June 2005, the
              EITF reached a consensus on the application guidance for Issue 05-6.
              EITF 05-6
              addresses the amortization period for leasehold improvements that were
              either
              acquired in a business combination or placed in service significantly
              after and
              not contemplated at or near the beginning of the initial lease term.
              For
              leasehold improvements acquired in a business combination, the amortization
              period is the shorter of the useful life of the assets or a term that
              includes
              required lease periods and renewals that are deemed to be reasonably
              assured at
              the date of acquisition. Leasehold improvements that are placed in
              service
              significantly after and not contemplated at or near the beginning of
              the lease
              term should be amortized over the shorter of the useful life of the
              assets or a
              term that includes required lease periods and renewals that are deemed
              to be
              reasonably assured at the date the leasehold improvements are purchased.
              This
              EITF was effective July 1, 2005 and is consistent with JCP&L's current
              accounting.
 
 *FIN
              47,
“Accounting for Conditional Asset Retirement Obligations - an interpretation
              of
              FASB Statement No. 143”*
 
 On
              March 30,
              2005, the FASB issued FIN 47 to clarify the scope and timing of liability
              recognition for conditional asset retirement obligations. Under this
              interpretation, companies are required to recognize a liability for
              the fair
              value of an asset retirement obligation that is conditional on a future
              event,
              if the fair value of the liability can be reasonably estimated. In
              instances
              where there is insufficient information to estimate the liability,
              the
              obligation is to be recognized in the first period in which sufficient
              information becomes available to estimate its fair value. If the fair
              value
              cannot be reasonably estimated, that fact and the reasons why must
              be disclosed.
              This Interpretation is effective for JCP&L in the fourth quarter of 2005.
              JCP&L is currently evaluating the effect this Interpretation will have
              on its financial statements.
  139
  *SFAS
                        154
                        - “Accounting Changes and Error Corrections - a replacement
                        of APB Opinion
                        No. 20 and FASB Statement No.
                        3”*
 
 In
              May 2005, the
              FASB issued SFAS 154 to change the requirements for accounting and
              reporting a
              change in accounting principle. It applies to all voluntary changes
              in
              accounting principle and to changes required by an accounting pronouncement
              when
              that pronouncement does not include specific transition provisions.
              This
              Statement requires retrospective application to prior periods’ financial
              statements of changes in accounting principle, unless it is impracticable
              to
              determine either the period-specific effects or the cumulative effect
              of the
              change. In those instances, this Statement requires that the new accounting
              principle be applied to the balances of assets and liabilities as of
              the
              beginning of the earliest period for which retrospective application
              is
              practicable and that a corresponding adjustment be made to the opening
              balance
              of retained earnings (or other appropriate components of equity or
              net assets in
              the statement of financial position) for that period rather than being
              reported
              in the Consolidated Statements of Income. This Statement also requires
              that a
              change in depreciation, amortization, or depletion method for long-lived,
              nonfinancial assets be accounted for as a change in accounting estimate
              affected
              by a change in accounting principle. The provisions of this Statement
              are
              effective for accounting changes and corrections of errors made in
              fiscal years
              beginning after December 15, 2005. JCP&L will adopt this Statement
              effective January 1, 2006.
 
 *SFAS
                        153,
                        “Exchanges of Nonmonetary Assets - an amendment of APB Opinion
                        No.
                        29”*
 
 In
              December 2004,
              the FASB issued SFAS 153 amending APB 29, which was based on the principle
              that
              nonmonetary assets should be measured based on the fair value of the
              assets
              exchanged. The guidance in APB 29 included certain exceptions to that
              principle.
              SFAS 153 eliminates the exception from fair value measurement for nonmonetary
              exchanges of similar productive assets and replaces it with an exception
              for
              exchanges that do not have commercial substance. This Statement specifies
              that a
              nonmonetary exchange has commercial substance if the future cash flows
              of the
              entity are expected to change significantly as a result of the exchange.
              The
              provisions of this Statement are effective January 1, 2006 for
              FirstEnergy.
              This FSP is not expected to have a material impact on JCP&L's financial
              statements.
 
 *SFAS
              151,
“Inventory Costs - an amendment of ARB No. 43, Chapter 4”*
 
 In
              November 2004,
              the FASB issued SFAS 151 to clarify the accounting for abnormal amounts
              of idle
              facility expense, freight, handling costs and wasted material (spoilage).
              Previous guidance stated that in some circumstances these costs may
              be “so
              abnormal” that they would require treatment as current period costs. SFAS 151
              requires abnormal amounts for these items to always be recorded as
              current
              period costs. In addition, this Statement requires that allocation
              of fixed
              production overheads to the cost of conversion be based on the normal
              capacity
              of the production facilities. The provisions of this statement are
              effective for
              inventory costs incurred by JCP&L beginning January 1, 2006. JCP&L
              is currently evaluating this Standard and does not expect it to have
              a material
              impact on the financial statements.
 
 *FSP
              FAS 115-1,
              "The Meaning of Other-Than-Temporary Impairment and its Application
              to Certain
              Investments"*
 
 In
              September 2005,
              the FASB finalized and renamed EITF 03-1 and 03-1-a to FSP FAS 115-1.
              FSP FAS
              115-1 will (1) supersede Issue 03-1 and EITF topic No. D-44, "Recognition
              of
              Other Than Temporary Impairment upon the Planned Sale of a Security
              Whose Cost
              Exceeds Fair Value," (2) clarify that an investor should recognize
              an impairment
              loss no later than when the impairment is deemed other than temporary,
              even if a
              decision to sell has not been made, and (3) be effective for
              other-than-temporary impairment and analyses conducted in periods beginning
              after September 15, 2005. The FASB expects to issue this FSP
              in the fourth
              quarter of 2005, which would require prospective application for reporting
              periods beginning after December 15, 2005. JCP&L is currently evaluating
              this FSP and any impact on its investments.
 140
 
  **METROPOLITAN
                            EDISON COMPANY****CONSOLIDATED
                            STATEMENTS OF INCOME AND COMPREHENSIVE INCOME****(Unaudited)****Three
                            Months Ended**
                        
                        **Nine
                            Months Ended****September
                            30,**
                        
                        **September
                            30,****2005**
                        
                        **2004**
                        
                        **2005**
                        
                        **2004*****(In
                            thousands)*****OPERATING
                            REVENUES**
                        
                        $
                        333,180
                        
                        $
                        285,419
                        
                        $
                        892,097
                        
                        $
                        788,361**OPERATING
                            EXPENSES AND TAXES:**Purchased
                            power
                        
                        
                        186,148
                        
                        
                        146,938
                        
                        
                        467,911
                        
                        
                        421,660Other
                            operating costs
                        
                        
                        81,774
                        
                        
                        50,141
                        
                        
                        192,892
                        
                        
                        130,210Provision
                            for
                            depreciation
                        
                        
                        9,323
                        
                        
                        10,648
                        
                        
                        32,221
                        
                        
                        30,370Amortization
                            of regulatory assets
                        
                        
                        32,853
                        
                        
                        30,291
                        
                        
                        86,760
                        
                        
                        78,737General
                            taxes
                        
                        
                        19,906
                        
                        
                        18,680
                        
                        
                        56,201
                        
                        
                        53,103Income
                            taxes
                        
                        
                        (2,111
                        )
                        
                        8,448
                        
                        
                        9,754
                        
                        
                        17,179Total
                            operating expenses and taxes
                        
                        
                        327,893
                        
                        
                        265,146
                        
                        
                        845,739
                        
                        
                        731,259**OPERATING
                            INCOME**
                        
                        
                        5,287
                        
                        
                        20,273
                        
                        
                        46,358
                        
                        
                        57,102**OTHER
                            INCOME (net of income taxes)**
                        
                        
                        6,459
                        
                        
                        6,888
                        
                        
                        19,897
                        
                        
                        18,530**NET
                            INTEREST CHARGES:**Interest
                            on
                            long-term debt
                        
                        
                        8,941
                        
                        
                        8,823
                        
                        
                        27,886
                        
                        
                        31,208Allowance
                            for
                            borrowed funds used during construction
                        
                        
                        (150
                        )
                        
                        (65
                        )
                        
                        (401
                        )
                        
                        (208
                        )Other
                            interest expense
                        
                        
                        1,950
                        
                        
                        1,326
                        
                        
                        5,626
                        
                        
                        2,846Net
                            interest
                            charges
                        
                        
                        10,741
                        
                        
                        10,084
                        
                        
                        33,111
                        
                        
                        33,846**NET
                            INCOME**
                        
                        
                        1,005
                        
                        
                        17,077
                        
                        
                        33,144
                        
                        
                        41,786**OTHER
                            COMPREHENSIVE INCOME (LOSS):**Unrealized
                            gain (loss) on derivative hedges
                        
                        
                        84
                        
                        
                        84
                        
                        
                        252
                        
                        
                        (3,182
                        )Unrealized
                            gain (loss) on available for sale securities
                        
                        
                        67
                        
                        
                        -
                        
                        
                        67
                        
                        
                        (53
                        )Other
                            comprehensive income (loss)
                        
                        
                        151
                        
                        
                        84
                        
                        
                        319
                        
                        
                        (3,235
                        )Income
                            tax
                            expense (benefit) related to other comprehensive income
                        
                        
                        62
                        
                        
                        (1,314
                        )
                        
                        132
                        
                        
                        (1,342
                        )Other
                            comprehensive income (loss), net of tax
                        
                        
                        89
                        
                        
                        1,398
                        
                        
                        187
                        
                        
                        (1,893
                        )**TOTAL
                            COMPREHENSIVE INCOME**
                        
                        $
                        1,094
                        
                        $
                        18,475
                        
                        $
                        33,331
                        
                        $
                        39,893The
                            preceding
                            Notes to Consolidated Financial Statements as they relate
                            to Metropolitan
                            Edison Company are an integral part of these statements.
   141
  **METROPOLITAN
                            EDISON COMPANY****CONSOLIDATED
                            BALANCE SHEETS****(Unaudited)****September
                            30,**
                        
                        **December
                            31,****2005**
                        
                        **2004*****(In
                            thousands)*****ASSETS****UTILITY
                            PLANT:**In
                            service
                        
                        $
                        1,841,450
                        
                        $
                        1,800,569Less
                            -
                            Accumulated provision for depreciation
                        
                        
                        712,549
                        
                        
                        709,8951,128,901
                        
                        
                        1,090,674Construction
                            work in progress
                        
                        
                        7,458
                        
                        
                        21,7351,136,359
                        
                        
                        1,112,409**OTHER
                            PROPERTY AND INVESTMENTS:**Nuclear
                            plant
                            decommissioning trusts
                        
                        
                        229,437
                        
                        
                        216,951Long-term
                            notes receivable from associated companies
                        
                        
                        11,162
                        
                        
                        10,453Other
                        
                        
                        29,355
                        
                        
                        34,767269,954
                        
                        
                        262,171**CURRENT
                            ASSETS:**Cash
                            and cash
                            equivalents
                        
                        
                        120
                        
                        
                        120Notes
                            receivable from associated companies
                        
                        
                        15,793
                        
                        
                        18,769Receivables
                            -Customers
                            (less accumulated provisions of $4,320,000 and $4,578,000,respectively,
                            for uncollectible accounts)
                        
                        
                        131,213
                        
                        
                        119,858Associated
                            companies
                        
                        
                        1,401
                        
                        
                        118,245Other
                        
                        
                        7,684
                        
                        
                        15,493Prepayments
                            and other
                        
                        
                        13,285
                        
                        
                        11,057169,496
                        
                        
                        283,542**DEFERRED
                            CHARGES:**Goodwill
                        
                        
                        867,649
                        
                        
                        869,585Regulatory
                            assets
                        
                        
                        571,745
                        
                        
                        693,133Other
                        
                        
                        24,055
                        
                        
                        24,4381,463,449
                        
                        
                        1,587,156$
                        3,039,258
                        
                        $
                        3,245,278**CAPITALIZATION
                            AND LIABILITIES****CAPITALIZATION:**Common
                            stockholder's equity -Common
                            stock,
                            without par value, authorized 900,000 shares -859,500
                            shares
                            outstanding
                        
                        $
                        1,290,296
                        
                        $
                        1,289,943Accumulated
                            other comprehensive loss
                        
                        
                        (43,303
                        )
                        
                        (43,490
                        )Retained
                            earnings
                        
                        
                        28,110
                        
                        
                        38,966Total
                            common
                            stockholder's equity
                        
                        
                        1,275,103
                        
                        
                        1,285,419Long-term
                            debt
                            and other long-term obligations
                        
                        
                        594,116
                        
                        
                        701,7361,869,219
                        
                        
                        1,987,155**CURRENT
                            LIABILITIES:**Currently
                            payable long-term debt
                        
                        
                        100,000
                        
                        
                        30,435Short-term
                            borrowings -Associated
                            companies
                        
                        
                        76,755
                        
                        
                        80,090Other
                        
                        
                        -
                        
                        
                        -Accounts
                            payable -Associated
                            companies
                        
                        
                        39,505
                        
                        
                        88,879Other
                        
                        
                        30,966
                        
                        
                        26,097Accrued
                            taxes
                        
                        
                        2,247
                        
                        
                        11,957Accrued
                            interest
                        
                        
                        9,462
                        
                        
                        11,618Other
                        
                        
                        20,008
                        
                        
                        23,076278,943
                        
                        
                        272,152**NONCURRENT
                            LIABILITIES:**Accumulated
                            deferred income taxes
                        
                        
                        309,979
                        
                        
                        305,389Accumulated
                            deferred investment tax credits
                        
                        
                        10,250
                        
                        
                        10,868Power
                            purchase
                            contract loss liability
                        
                        
                        250,024
                        
                        
                        349,980Asset
                            retirement obligation
                        
                        
                        139,216
                        
                        
                        132,887Retirement
                            benefits
                        
                        
                        77,501
                        
                        
                        82,218Nuclear
                            fuel
                            disposal costs
                        
                        
                        39,213
                        
                        
                        38,408Other
                        
                        
                        64,913
                        
                        
                        66,221891,096
                        
                        
                        985,971**COMMITMENTS
                            AND CONTINGENCIES (Note 13)**$
                        3,039,258
                        
                        $
                        3,245,278The
                            preceding
                            Notes to Consolidated Financial Statements as they relate
                            to Metropolitan
                            Edison Company are an integral part of these balance
                            sheets.
   142
  **METROPOLITAN
                            EDISON COMPANY****CONSOLIDATED
                            STATEMENTS OF CASH FLOWS****(Unaudited)****Three
                            Months Ended**
                        
                        **Nine
                            Months Ended****September
                            30,**
                        
                        **September
                            30,****2005**
                        
                        **2004**
                        
                        **2005**
                        
                        **2004*****(In
                            thousands)*****CASH
                            FLOWS FROM OPERATING ACTIVITIES:**Net
                            income
                        
                        $
                        1,005
                        
                        $
                        17,077
                        
                        $
                        33,144
                        
                        $
                        41,786Adjustments
                            to reconcile net income to net cash fromoperating
                            activities -Provision
                            for
                            depreciation
                        
                        
                        9,323
                        
                        
                        10,648
                        
                        
                        32,221
                        
                        
                        30,370Amortization
                            of regulatory assets
                        
                        
                        32,853
                        
                        
                        30,291
                        
                        
                        86,760
                        
                        
                        78,737Deferred
                            costs recoverable as regulatory assets
                        
                        
                        8,521
                        
                        
                        (15,629
                        )
                        
                        (21,491
                        )
                        
                        (45,616
                        )Deferred
                            income taxes and investment tax credits, net
                        
                        
                        (8,438
                        )
                        
                        666
                        
                        
                        (10,336
                        )
                        
                        (4,853
                        )Accrued
                            retirement benefit obligation
                        
                        
                        (1,514
                        )
                        
                        (273
                        )
                        
                        (4,717
                        )
                        
                        492Accrued
                            compensation, net
                        
                        
                        1,527
                        
                        
                        649
                        
                        
                        211
                        
                        
                        201Pension
                            trust
                            contribution
                        
                        
                        -
                        
                        
                        (38,823
                        )
                        
                        -
                        
                        
                        (38,823
                        )Decrease
                            (increase) in operating assets -Receivables
                        
                        
                        3,088
                        
                        
                        (2,599
                        )
                        
                        113,298
                        
                        
                        29,943Materials
                            and
                            supplies
                        
                        
                        (1
                        )
                        
                        5
                        
                        
                        (19
                        )
                        
                        41Prepayments
                            and other current assets
                        
                        
                        18,978
                        
                        
                        14,298
                        
                        
                        (2,209
                        )
                        
                        (15,027
                        )Increase
                            (decrease) in operating liabilities -Accounts
                            payable
                        
                        
                        6,088
                        
                        
                        (12,536
                        )
                        
                        (44,505
                        )
                        
                        (17,857
                        )Accrued
                            taxes
                        
                        
                        (4,526
                        )
                        
                        (145
                        )
                        
                        (9,710
                        )
                        
                        (6,255
                        )Accrued
                            interest
                        
                        
                        (1,269
                        )
                        
                        (3,006
                        )
                        
                        (2,156
                        )
                        
                        (127
                        )Other
                        
                        
                        (7,701
                        )
                        
                        (7,356
                        )
                        
                        (24,063
                        )
                        
                        (9,581
                        )Net
                            cash
                            provided from (used for) operating activities
                        
                        
                        57,934
                        
                        
                        (6,733
                        )
                        
                        146,428
                        
                        
                        43,431**CASH
                            FLOWS FROM FINANCING ACTIVITIES:**New
                            Financing-Long-term
                            debt
                        
                        
                        -
                        
                        
                        -
                        
                        
                        -
                        
                        
                        247,607Short-term
                            borrowings, net
                        
                        
                        -
                        
                        
                        70,000
                        
                        
                        -
                        
                        
                        4,665Redemptions
                            and Repayments-Long-term
                            debt
                        
                        
                        -
                        
                        
                        (45,936
                        )
                        
                        (37,830
                        )
                        
                        (196,371
                        )Short-term
                            borrowings, net
                        
                        
                        (24,266
                        )
                        
                        -
                        
                        
                        (3,335
                        )
                        
                        -Dividend
                            Payments-Common
                            stock
                        
                        
                        (10,000
                        )
                        
                        (10,000
                        )
                        
                        (44,000
                        )
                        
                        (35,000
                        )Net
                            cash
                            provided from (used for) financing activities
                        
                        
                        (34,266
                        )
                        
                        14,064
                        
                        
                        (85,165
                        )
                        
                        20,901**CASH
                            FLOWS FROM INVESTING ACTIVITIES:**Property
                            additions
                        
                        
                        (21,680
                        )
                        
                        (12,390
                        )
                        
                        (56,075
                        )
                        
                        (33,733
                        )Contributions
                            to nuclear decommissioning trusts
                        
                        
                        (2,370
                        )
                        
                        (2,371
                        )
                        
                        (7,112
                        )
                        
                        (7,113
                        )Loan
                            repayments from (loans to) associated companies, net
                        
                        
                        (1,072
                        )
                        
                        17,989
                        
                        
                        2,267
                        
                        
                        (13,046
                        )Other
                        
                        
                        1,454
                        
                        
                        (10,559
                        )
                        
                        (343
                        )
                        
                        (10,441
                        )Net
                            cash
                            provided used for investing activities
                        
                        
                        (23,668
                        )
                        
                        (7,331
                        )
                        
                        (61,263
                        )
                        
                        (64,333
                        )Net
                            change in
                            cash and cash equivalents
                        
                        
                        -
                        
                        
                        -
                        
                        
                        -
                        
                        
                        (1
                        )Cash
                            and cash
                            equivalents at beginning of period
                        
                        
                        120
                        
                        
                        120
                        
                        
                        120
                        
                        
                        121Cash
                            and cash
                            equivalents at end of period
                        
                        $
                        120
                        
                        $
                        120
                        
                        $
                        120
                        
                        $
                        120The
                            preceding
                            Notes to Consolidated Financial Statements as they relate
                            to Metropolitan
                            Edison Company are an integral part of these statements.
 
 143
 ***Report
                    of Independent Registered Public Accounting Firm***
 
 
 
 
 
 
 
 
 
 To
                    the Stockholders
                    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, 2005, and the related consolidated
                    statements of income and comprehensive income and cash flows
                    for each of the
                    three-month and nine-month periods ended September 30, 2005 and
                    2004. 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
                    previously
                    audited, in accordance with the standards of the Public Company
                    Accounting
                    Oversight Board (United States), the consolidated balance sheet
                    as of
                    December 31, 2004, and the related consolidated statements
                    of income,
                    capitalization, common stockholder’s 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,
                    2004 and the effectiveness of the Company’s internal control over financial
                    reporting as of December 31, 2004; 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) 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 March 7, 2005, 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 information as of December 31,
                    2004, is fairly stated in all material respects in relation to
                    the consolidated
                    balance sheet from which it has been derived.
 
 
 
 
 PricewaterhouseCoopers
                    LLP
 Cleveland,
                    Ohio
 November
                    1,
                    2005
  144
  **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. Met-Ed has unbundled the
                    price for
                    electricity into its component elements - including generation,
                    transmission,
                    distribution and transition charges. Met-Ed continues to deliver
                    power to homes
                    and businesses through its existing distribution system.
 
 **Results
                    of Operations**
 
 Net
                    income
                    decreased to $1
                    million for the
                    third quarter of 2005 from $17 million in the third quarter of
                    2004. The decrease
                    in net
                    income primarily resulted from higher purchased power costs,
                    transmission
                    expenses, and amortization of regulatory assets, partially offset
                    by higher
                    operating revenues and lower depreciation and income taxes. For
                    the first nine
                    months of 2005, net income decreased to $33 million from $42
                    million in the same
                    period of 2004. The decrease in n et
                    income primarily
                    resulted from higher purchased power costs, transmission expenses,
                    and
                    amortization of regulatory assets, partially offset by higher
                    operating revenues
                    and other income and lower income taxes as discussed below.
 
 Operating
                    revenues
                    increased by $48 million, or 16.7%, in the third quarter of 2005
                    and $104
                    million, or 13.2%, in the first nine months of 2005, compared
                    with the same
                    periods of 2004. Increases in both periods were due, in part,
                    to higher retail
                    generation electric revenues from all customer sectors ($17 million
                    for the
                    third quarter and $41 million for the first nine months of 2005).
                    The increases
                    in retail generation KWH sales for both periods of 2005 were
                    mainly attributable
                    to warmer weather and reduced customer shopping - primarily in
                    the industrial
                    sector. Industrial customer shopping decreased by 4.9% and 11.2%
                    percentage
                    points in the third quarter and first nine months of 2005, respectively.
                    While
                    higher generation sales in the third quarter of 2005 were offset
                    by slightly
                    lower composite unit prices, overall higher composite unit prices
                    during the
                    nine-month period also contributed to the increase in generation
                    revenues.
 
 Revenues
                    from
                    distribution throughput increased by $13 million in the third
                    quarter and by $23
                    million in the first nine months of 2005 compared with the same
                    periods of 2004.
                    Increases in both periods of 2005 were primarily due to higher
                    KWH deliveries
                    and slightly higher unit prices. Increased transmission revenues
                    of $17 million
                    in the third quarter and $32 million in the first nine months
                    of 2005 also
                    contributed to higher operating revenues. These increases were
                    due to a change
                    in the power supply agreement with FES in the second quarter
                    of 2004. This
                    change also resulted in higher transmission expenses as discussed
                    further below.
                    In the first nine months of 2005, operating revenues also included
                    a $4 million
                    payment received 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 specific levels and are credited to
                    Met-Ed’s customers,
                    resulting in no net impact to earnings.
 
 Changes
                    in KWH
                    sales by customer class in the three months and nine months ended
                    September 30, 2005 compared to the same periods of 2004
                    are summarized in
                    the following table:
 **Three**
                        
                        **Nine****Changes
                            in KWH Sales**
                        
                        **Months**
                        
                        **Months****Increase
                            (Decrease)**Retail
                            Electric Generation:Residential
                        
                        
                        15.5
                        %
                        
                        7.6
                        %Commercial
                        
                        
                        10.1
                        %
                        
                        7.6
                        %Industrial
                        
                        
                        9.1
                        %
                        
                        17.0
                        %**Total
                            Retail Electric Generation Sales**
                        
                        
                        11.9
                        **%**
                        
                        9.9
                        **%**Distribution
                            Deliveries:Residential
                        
                        
                        15.5
                        %
                        
                        7.5
                        %Commercial
                        
                        
                        10.0
                        %
                        
                        6.7
                        %Industrial
                        
                        
                        3.2
                        %
                        
                        1.9
                        %**Total
                            Distribution Deliveries**
                        
                        
                        10.0
                        **%**
                        
                        5.6
                        **%**
 
 145
 *Operating
                    Expenses and Taxes*
 
 Total
                    operating
                    expenses and taxes increased by $63 million in the third quarter
                    and by $114
                    million in the first nine months of 2005 compared with the same
                    periods of 2004.
                    The following table presents changes from the prior year by expense
                    category:
 **Three**
                        
                        **Nine****Operating
                            Expenses and Taxes - Changes**
                        
                        **Months**
                        
                        **Months*****(In
                            millions)*****Increase
                            (Decrease)**Purchased
                            power costs
                        
                        $
                        39
                        
                        $
                        46Other
                            operating costs
                        
                        
                        32
                        
                        
                        62Provision
                            for
                            depreciation
                        
                        
                        (1
                        )
                        
                        2Amortization
                            of regulatory assets
                        
                        
                        3
                        
                        
                        8General
                            taxes
                        
                        
                        1
                        
                        
                        3Income
                            taxes
                        
                        
                        (11
                        )
                        
                        (7
                        )**Net
                            increase in operating expenses and taxes**
                        
                        $
                        63
                        
                        $
                        114
 
 Purchased
                      power
                      costs increased by $39 million in the third quarter and $46
                      million in the first
                      nine months of 2005 compared with the same periods of 2004.
                      The increases in
                      both periods were primarily due to increased third party power
                      purchases ($47
                      million in the third quarter and $92 million in the first nine
                      months of 2005)
                      and NUG contract purchases ($21 million in the third quarter
                      and $29 million in
                      the first nine months of 2005) partially offset by reduced
                      purchased power from
                      FES ($30 million in the third quarter and $77 million in the
                      first nine months
                      of 2005). These changes, for both periods, were due to increased
                      KWH purchased
                      to meet increased retail generation sales requirements offset
                      by slightly lower
                      unit costs.
 
 Other
                      operating
                      costs increased by $32 million in the third quarter and by
                      $62 million in first
                      nine months of 2005 compared with the same periods of 2004.
                      The increases in
                      both periods were primarily caused by higher PJM congestion
                      charges and
                      transmission expenses as a result of the change in the power
                      supply agreement
                      with FES discussed above.
 
 In
                      the first nine
                      months of 2005, depreciation expense increased due to additions
                      to the asset
                      base and higher costs to decommission the Saxton nuclear plant
                      as compared to
                      the same period of 2004. For both periods of 2005, regulatory
                      asset amortization
                      reflected increases associated with the level of CTC revenue
                      recovery, partially
                      offset by lower amortization related to above market NUG costs
                      as compared to
                      the prior year periods.
 
 General
                      taxes
                      increased in both periods primarily as a result of higher gross
                      receipt taxes
                      associated with the increase in KWH sales. Income taxes decreased
                      in the third
                      quarter and first nine months of 2005 due to lower taxable
                      income.
 
 **Capital
                      Resources and Liquidity**
 
 Met-Ed’s
                      cash
                      requirements for the remainder of 2005, for operating expenses,
                      construction
                      expenditures and scheduled debt maturities are expected to
                      be met with cash from
                      operations.
 
 *Changes
                      in Cash
                      Position*
 
 As
                      of
                      September 30, 2005, Met-Ed’s cash and cash equivalents of $120,000 remained
                      unchanged from December 31, 2004.
  146
 *Cash
                    Flows From
                    Operating Activities*
 
 Cash
                    provided from
                    (used for) operating activities during the third quarter and
                    first nine months
                    of 2005, compared with the corresponding periods of 2004 were
                    as
                    follows:
 **Three
                            Months Ended**
                        
                        **Nine
                            Months Ended****September
                            30,**
                        
                        **September
                            30,****Operating
                            Cash Flows**
                        
                        **2005**
                        
                        **2004**
                        
                        **2005**
                        
                        **2004*****(In
                            millions)***Cash
                            earnings(1)
                        
                        $
                        43
                        
                        $
                        27
                        
                        $
                        116
                        
                        $
                        85Pension
                            trust
                            contribution(2)
                        
                        
                        -
                        
                        
                        (23
                        )
                        
                        -
                        
                        
                        (23
                        )Working
                            capital and other
                        
                        
                        15
                        
                        
                        (11
                        )
                        
                        30
                        
                        
                        (19
                        )Total
                            cash
                            flows from operating activities
                        
                        $
                        58
                        
                        $
                        (7
                        )
                        $
                        146
                        
                        $
                        43(1)Cash
                            earnings is a non-GAAP measure (see reconciliation below).(2)Pension
                            trust
                            contribution net of $16 million of income tax benefits.
  Cash
                    earnings, as
                    disclosed 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. The following
                    table reconciles
                    cash earnings with net income.
 **Three
                            Months Ended**
                        
                        **Nine
                            Months Ended****September
                            30,**
                        
                        **September
                            30,****Reconciliation
                            of Cash Earnings**
                        
                        **2005**
                        
                        **2004**
                        
                        **2005**
                        
                        **2004*****(In
                            millions)***Net
                            income
                            (GAAP)
                        
                        $
                        1
                        
                        $
                        17
                        
                        $
                        33
                        
                        $
                        42Non-cash
                            charges (credits):Provision
                            for
                            depreciation
                        
                        
                        9
                        
                        
                        11
                        
                        
                        32
                        
                        
                        30Amortization
                            of regulatory assets
                        
                        
                        33
                        
                        
                        30
                        
                        
                        87
                        
                        
                        79Deferred
                            costs recoverable as regulatory assets
                        
                        
                        8
                        
                        
                        (16
                        )
                        
                        (22
                        )
                        
                        (46
                        )Deferred
                            income taxes and investment tax credits, net
                        
                        
                        (8
                        )
                        
                        (16
                        )
                        
                        (10
                        )
                        
                        (21
                        )Other
                            non-cash charges
                        
                        
                        -
                        
                        
                        1
                        
                        
                        (4
                        )
                        
                        1Cash
                            earnings
                            (Non-GAAP)
                        
                        $
                        43
                        
                        $
                        27
                        
                        $
                        116
                        
                        $
                        85
  The
                    $16 million and
                    $31 million increases in cash earnings for the third quarter
                    and first nine
                    months of 2005, respectively, are described above under “Results of Operations”.
                    Net cash from operating activities increased in the third quarter
                    and the first
                    nine months due to the absence of a $23 million after-tax voluntary
                    pension
                    contribution made in the third quarter of 2004. The $26 million
                    change in
                    working capital in the third quarter of 2005 primarily resulted
                    from changes of
                    $6 million in accounts receivable, $19 million in accounts payable
                    and $5
                    million in prepayments, offset by a change of $4 million in accrued
                    taxes. The
                    $49 million change in working capital for the first nine months
                    of 2005
                    primarily resulted from net changes in accounts receivable and
                    accounts payable
                    from associated companies of $52 million and $13 million in prepayments,
                    partially offset by changes of $11 million in customer deposits,
                    $3 million in
                    accrued taxes and $2 million in accrued interest.
 
 *Cash
                    Flows From
                    Financing Activities*
 
 For
                    the third
                    quarter of 2005, net cash used for financing activities was $34
                    million compared
                    to $14 million of cash provided from financing activities in
                    the third quarter
                    of 2004. The $48 million decrease resulted primarily from a $70
                    million
                    reduction in new debt financing compared to the third quarter
                    of 2004 offset in
                    part by a $22 million reduction in debt redemptions. For the
                    first nine months
                    of 2005, net cash used for financing activities was $85 million
                    compared to $21
                    million of net cash provided from financing activities in the
                    same period of
                    2004. The $106 million change reflected a $252 million reduction
                    in new debt
                    financing and a $9 million increase in common stock dividends
                    to FirstEnergy,
                    partially offset by a $155 million decrease in debt redemptions
                    compared to the
                    same period of 2004.
 
 As
                    of
                    September 30, 2005, Met-Ed had approximately $16 million
                    of cash and
                    temporary investments (including short-term notes receivable
                    from associated
                    companies) and $77 million of short-term borrowings outstanding.
                    Met-Ed has
                    authorization from the SEC to incur short-term debt up to $250
                    million
                    (including the utility money pool). Under the terms of Met-Ed’s senior note
                    indenture, no more first mortgage bonds can be issued as long
                    as the senior
                    bonds are outstanding. Met-Ed had no restrictions on the issuance
                    of preferred
                    stock.
   147
 
 Met-Ed
                  Funding LLC
                  (Met-Ed Funding), a wholly owned subsidiary of Met-Ed, is a limited
                  liability
                  company whose borrowings are secured by customer accounts receivable
                  purchased
                  from Met-Ed. Met-Ed Funding can borrow up to $80 million under
                  a receivables
                  financing arrangement. 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. On July
                  15, 2005, the
                  facility was renewed until June 29, 2006. As of September 30,
                  2005,
                  the facility was undrawn. The annual facility fee is 0.25% on the
                  entire finance
                  limit.
 
 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 pools and
                  tracks surplus funds of FirstEnergy and the respective 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 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
                  the pool and is
                  based on the average cost of funds available through the pool.
                  The average
                  interest rate for borrowings in the third quarter of 2005 was
                  3.50%.
 
 On
                  June 14,
                  2005, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI,
                  as borrowers, entered into a syndicated $2 billion five-year revolving
                  credit
                  facility. Borrowings under the facility are available to each borrower
                  separately and mature on the earlier of 364 days from the date
                  of borrowing or
                  the commitment termination date, as the same may be extended. Met-Ed’s borrowing
                  limit under the facility is $250 million.
 
 Met-Ed’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 and Fitch
                  on all securities is stable. Moody’s outlook on all securities is
                  positive.
 
 On
                  July 18,
                  2005, Moody’s revised its rating outlook on FirstEnergy and its subsidiaries
                  to
                  positive from stable. Moody’s stated that the revision to FirstEnergy’s outlook
                  resulted from steady financial improvement and steps taken by management
                  to
                  improve operations, including the stabilization of its nuclear
                  operations.
                  Moody’s further stated that the revision in their outlook recognized
                  management’s regional strategy of focusing on its core utility businesses
                  and
                  the improvement in FirstEnergy’s credit profile stemming from the application of
                  free cash flow toward debt reduction. Moody’s noted that a ratings upgrade could
                  be considered if FirstEnergy continues to achieve planned improvements
                  in its
                  operations and balance sheet.
 
 On
                  October 3,
                  2005, S&P raised its corporate credit rating on FirstEnergy and the EUOC
                  to
                  'BBB' from 'BBB-'. At the same time, S&P raised the senior unsecured ratings
                  at the holding company to 'BBB-' from 'BB+' and each of the EUOC
                  by one notch
                  above the previous rating. S&P noted that the upgrade followed the
                  continuation of a good operating track record, specifically for
                  the nuclear
                  fleet through the third quarter 2005. S&P also stated that FirstEnergy’s
                  rating reflects the benefits of supportive regulation, low-cost
                  base load
                  generation fleet, low-risk transmission and distribution operations
                  and rate
                  certainty in Ohio. FirstEnergy’s ability to consistently generate free cash
                  flow, good liquidity, and an improving financial profile were also
                  noted as
                  strengths.
 
 *Cash
                  Flows From
                  Investing Activities*
 
 In
                  the third
                  quarter of 2005, net cash used for investing activities totaled
                  $24 million,
                  compared to $7 million in the third quarter of 2004. The change
                  in the third
                  quarter of 2005 primarily resulted from a $19 million increase
                  in loan
                  repayments to associated companies and a $9 million increase in
                  property
                  additions, partially offset by a $9 million capital transfer from
                  FESC in the
                  third quarter of 2004. In the first nine months of 2005, net cash
                  used for
                  investing activities totaled $61 million compared to $64 million
                  in the same
                  period of 2004. The change resulted from a $15 million increase
                  in loan
                  repayments from associated companies and the previously mentioned
                  capital
                  transfer, partially offset by a $22 million increase in property
                  additions.
                  Expenditures for property additions primarily support Met-Ed’s energy delivery
                  operations.
 
 Met-Ed's
                  capital
                  spending for the period 2005 through 2007 is expected to be about
                  $205 million,
                  of which approximately $68 million applies to 2005. In the last
                  quarter of 2005,
                  capital requirements for property additions are expected to be
                  about $14
                  million. These cash requirements are expected to be satisfied from
                  internal cash
                  and short-term credit arrangements. Met-Ed has no additional requirements
                  for
                  maturing long-term debt during the remainder of 2005.
 
 **Market
                  Risk Information**
 
 Met-Ed
                  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
                  management oversight to risk management activities.
 
 148
 *Commodity
                    Price
                    Risk*
 
 Met-Ed
                    is exposed
                    to price risk primarily resulting from fluctuating electricity
                    and natural gas
                    prices. To manage the volatility relating to these exposures,
                    it uses a variety
                    of non-derivative and derivative instruments, including options
                    and futures
                    contracts. The derivatives are used for hedging purposes. Most
                    of Met-Ed's
                    non-hedge derivative contracts represent non-trading positions
                    that do not
                    qualify for hedge treatment under SFAS 133. As of September 30,
                    2005,
                    Met-Ed’s commodity derivative contract was an embedded option with a
                    fair value
                    of $28 million. A $4 million net decrease in the value of this
                    asset was
                    recorded as a decrease in regulatory liabilities, and therefore,
                    had no impact
                    on net income.
 
 The
                    valuation of
                    derivative commodity 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 derivative contracts
                    as of
                    September 30, 2005 are summarized by year in the following
                    table:
 **Sources
                            of Information -****Fair
                            Value by Contract Year**
                        
                        
                        
                        **2005**(1)
                        
                        **2006**
                        
                        **2007**
                        
                        **2008**
                        
                        **2009**
                        
                        **Thereafter**
                        
                        **Total**Prices
                            based
                            on external sources(2)
                        
                        
                        
                        
                        $
                        5
                        
                        $
                        5
                        
                        $
                        5
                        
                        $
                        -
                        
                        $
                        -
                        
                        $
                        -
                        
                        $
                        15Prices
                            based
                            on models
                        
                        
                        
                        
                        
                        -
                        
                        
                        -
                        
                        
                        -
                        
                        
                        5
                        
                        
                        4
                        
                        
                        4
                        
                        
                        13Total
                        
                        
                        
                        
                        $
                        5
                        
                        $
                        5
                        
                        $
                        5
                        
                        $
                        5
                        
                        $
                        4
                        
                        $
                        4
                        
                        $
                        28(1)For
                            the
                            last quarter of 2005.
                          (2)Broker
                            quote sheets.
 
 Met-Ed
                    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 derivative instruments would not have had a material effect
                    on its
                    consolidated financial position or cash flows as of September 30,
                    2005.
 
 *Equity
                    Price
                    Risk*
 
 Included
                    in
                    Met-Ed's nuclear decommissioning trust investments are marketable
                    equity
                    securities carried at their market value of approximately $138
                    million as of
                    September 30, 2005 and $134 million as of December 31,
                    2004. A
                    hypothetical 10% decrease in prices quoted by stock exchanges
                    would result in a
                    $14 million reduction in fair value as of September 30,
                    2005.
 
 **Regulatory
                    Matters**
  Regulatory
                    assets
                    are costs which have been authorized by the PPUC and the FERC
                    for recovery from
                    customers in future periods and, without such authorization,
                    would have been
                    charged to income when incurred. Met-Ed's regulatory assets as
                    of
                    September 30, 2005 and December 31, 2004 were $572
                    million and $693
                    million, respectively.
 
 In
                    accordance with
                    PPUC directives, Met-Ed and Penelec have been negotiating with
                    interested
                    parties in an attempt to resolve the merger savings issues that
                    are the subject
                    of remand from the Commonwealth Court. Met-Ed’s and Penelec’s combined portion
                    of total merger savings is estimated to be approximately $31.5
                    million. On
                    April 13, 2005, the Commonwealth Court issued an interim
                    order in the
                    remand proceeding that the parties should report the status of
                    the negotiations
                    to the PPUC with a copy to the ALJ. The parties exchanged settlement
                    proposals
                    in May and June 2005 and continue to have settlement discussions.
 
 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 judge, 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.
 149
  Met-Ed
                    purchases a
                    portion of its PLR requirements from FES through a wholesale
                    power sales
                    agreement. The PLR sale is automatically extended for each successive
                    calendar
                    year unless any party elects to cancel the agreement by November 1
                    of the
                    preceding year. Under the terms of the wholesale 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 NUG
                    contracts and
                    other power contracts with nonaffiliated third party suppliers.
                    This 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. Met-Ed is authorized to defer differences
                    between NUG
                    contract costs and current market prices. On
                    November 1,
                    2005, FES and the other parties to the wholesale power agreement
                    amended the
                    agreement to provide FES the right over the next year to terminate
                    the agreement
                    at any time upon 60 days notice.If
                    the wholesale
                    power agreement were terminated, Met-Ed and Penelec would need
                    to satisfy the
                    applicable portion of their PLR obligations from other sources
                    at prevailing
                    prices, which are likely to be higher than the current price
                    charged by FES
                    under the agreement and, as a result, Met-Ed’s and Penelec’s purchased power
                    costs could materially increase.
 
 On
                    January 12,
                    2005, Met-Ed filed a request with the PPUC for deferral of transmission-related
                    costs beginning January 1, 2005, estimated to be approximately
                    $4 million
                    per month. The
                    OCA, OSBA, OTS,
                    MEIUG, PICA, Allegheny Electric Cooperative and Pennsylvania
                    Rural Electric
                    Association have all intervened in the case. To date no hearing
                    schedule has
                    been established, and Met-Ed has not yet implemented deferral
                    accounting for
                    these costs.
 
 On
                    January 31,
                    2005, certain PJM transmission owners made three filings 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.
                    Second, the FERC
                    approved the proposed Schedule 12 rate harmonization. Third,
                    the FERC accepted
                    the proposed formula rate, subject to referral and hearing procedures.
                    On
                    June 30, 2005, the PJM transmission owners filed a request
                    for rehearing of
                    the May 31, 2005 order. The rate design and formula rate
                    filings continue
                    to be litigated before the FERC. The outcome of these two cases
                    cannot be
                    predicted.
 
 See
                    Note 14 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 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 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, 2005, based on estimates of the total costs
                    of cleanup,
                    Met-Ed’s proportionate responsibility for such costs and the financial
                    ability
                    of other nonaffiliated entities to pay.
 
 FirstEnergy
                    plans
                    to issue a report regarding its response to air emission requirements.
                    FirstEnergy expects to complete the report by December 1,
                    2005.
 
 See
                    Note 13(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 Met-Ed's normal business operations pending against
                    Met-Ed. The other
                    material items not otherwise discussed above are described below.
 150
  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 concludes, 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 website (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 also is proceeding
                    with the
                    implementation of the recommendations regarding enhancements
                    to regional
                    reliability 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, and therefore FirstEnergy has not accrued a liability
                    as of
                    September 30, 2005 for any expenditures in excess of those
                    actually
                    incurred through that date. 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 that could
                    require additional, material expenditures. Finally, the PUCO
                    is continuing to
                    review FirstEnergy’s filing that addressed upgrades to control room computer
                    hardware and software and enhancements to the training of control
                    room
                    operators, before determining the next steps, if any, in the
                    proceeding.
 
 One
                    complaint was
                    filed on August 25, 2004 against FirstEnergy in the New York
                    State Supreme
                    Court. In this case, several plaintiffs in the New York City
                    metropolitan area
                    allege that they suffered damages as a result of the August 14,
                    2003 power
                    outages. None of the plaintiffs are customers of any FirstEnergy
                    affiliate.
                    FirstEnergy's motion to dismiss the case was granted on September 26,
                    2005.
                    Additionally, FirstEnergy Corp. was named in a complaint filed
                    in Michigan State
                    Court by an individual who is not a customer of any FirstEnergy
                    company. A
                    responsive pleading to this matter is not due until on or about
                    December 1,
                    2005. No estimate of potential liability has been undertaken
                    in this matter.
 
 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.
 
 See
                    Note 13(C) to
                    the consolidated financial statements for further details and
                    a complete
                    discussion of other legal proceedings.
 
 **New
                    Accounting Standards and Interpretations**
 
 *EITF
                    Issue
                    04-13, "Accounting for Purchases and Sales of Inventory with
                    the Same
                    Counterparty"*
  In
                    September 2005,
                    the EITF reached a final consensus on Issue 04-13 concluding
                    that two or more
                    legally separate exchange transactions with the same counterparty
                    should be
                    combined and considered as a single arrangement for purposes
                    of applying APB 29,
                    when the transactions were entered into "in contemplation" of
                    one another. If
                    two transactions are combined and considered a single arrangement,
                    the EITF
                    reached a consensus that an exchange of inventory should be accounted
                    for at
                    fair value. Although electric power is not capable of being held
                    in inventory,
                    there is no substantive conceptual distinction between exchanges
                    involving power
                    and other storable inventory. Therefore, Met-Ed will adopt this
                    EITF effective
                    for new arrangements entered into, or modifications or renewals
                    of existing
                    arrangements, in interim or annual periods beginning after March
                    15, 2006.
 151
  *EITF
                              Issue No. 05-6, "Determining the Amortization Period
                              for Leasehold
                              Improvements Purchased after Lease Inception or Acquired
                              in a Business
                              Combination"*
  In
                    June 2005, the
                    EITF reached a consensus on the application guidance for Issue
                    05-6. EITF 05-6
                    addresses the amortization period for leasehold improvements
                    that were either
                    acquired in a business combination or placed in service significantly
                    after and
                    not contemplated at or near the beginning of the initial lease
                    term. For
                    leasehold improvements acquired in a business combination, the
                    amortization
                    period is the shorter of the useful life of the assets or a term
                    that includes
                    required lease periods and renewals that are deemed to be reasonably
                    assured at
                    the date of acquisition. Leasehold improvements that are placed
                    in service
                    significantly after and not contemplated at or near the beginning
                    of the lease
                    term should be amortized over the shorter of the useful life
                    of the assets or a
                    term that includes required lease periods and renewals that are
                    deemed to be
                    reasonably assured at the date the leasehold improvements are
                    purchased. This
                    EITF was effective July 1, 2005 and is consistent with
                    Met-Ed's current
                    accounting.
 
 *FIN
                    47,
“Accounting for Conditional Asset Retirement Obligations - an
                    interpretation of
                    FASB Statement No. 143”*
 
 On
                    March 30,
                    2005, the FASB issued FIN 47 to clarify the scope and timing
                    of liability
                    recognition for conditional asset retirement obligations. Under
                    this
                    interpretation, companies are required to recognize a liability
                    for the fair
                    value of an asset retirement obligation that is conditional on
                    a future event,
                    if the fair value of the liability can be reasonably estimated.
                    In instances
                    where there is insufficient information to estimate the liability,
                    the
                    obligation is to be recognized in the first period in which sufficient
                    information becomes available to estimate its fair value. If
                    the fair value
                    cannot be reasonably estimated, that fact and the reasons why
                    must be disclosed.
                    This Interpretation is effective for Met-Ed in the fourth quarter
                    of 2005.
                    Met-Ed is currently evaluating the effect this Interpretation
                    will have on its
                    financial statements.
 
 *SFAS
                              154
                              - “Accounting Changes and Error Corrections - a replacement
                              of APB Opinion
                              No. 20 and FASB Statement No.
                              3”*
 
 In
                    May 2005, the
                    FASB issued SFAS 154 to change the requirements for accounting
                    and reporting a
                    change in accounting principle. It applies to all voluntary changes
                    in
                    accounting principle and to changes required by an accounting
                    pronouncement when
                    that pronouncement does not include specific transition provisions.
                    This
                    Statement requires retrospective application to prior periods’ financial
                    statements of changes in accounting principle, unless it is impracticable
                    to
                    determine either the period-specific effects or the cumulative
                    effect of the
                    change. In those instances, this Statement requires that the
                    new accounting
                    principle be applied to the balances of assets and liabilities
                    as of the
                    beginning of the earliest period for which retrospective application
                    is
                    practicable and that a corresponding adjustment be made to the
                    opening balance
                    of retained earnings (or other appropriate components of equity
                    or net assets in
                    the statement of financial position) for that period rather than
                    being reported
                    in the Consolidated Statements of Income. This Statement also
                    requires that a
                    change in depreciation, amortization, or depletion method for
                    long-lived,
                    nonfinancial assets be accounted for as a change in accounting
                    estimate affected
                    by a change in accounting principle. The provisions of this Statement
                    are
                    effective for accounting changes and corrections of errors made
                    in fiscal years
                    beginning after December 15, 2005. Met-Ed will adopt this
                    Statement
                    effective January 1, 2006.
 
 *SFAS
                              153,
                              “Exchanges of Nonmonetary Assets - an amendment of APB
                              Opinion No.
                              29”*
 
 In
                    December 2004,
                    the FASB issued SFAS 153 amending APB 29, which was based on
                    the principle that
                    nonmonetary assets should be measured based on the fair value
                    of the assets
                    exchanged. The guidance in APB 29 included certain exceptions
                    to that principle.
                    SFAS 153 eliminates the exception from fair value measurement
                    for nonmonetary
                    exchanges of similar productive assets and replaces it with an
                    exception for
                    exchanges that do not have commercial substance. This Statement
                    specifies that a
                    nonmonetary exchange has commercial substance if the future cash
                    flows of the
                    entity are expected to change significantly as a result of the
                    exchange. The
                    provisions of this Statement are effective January 1,
                    2006 for Met-Ed. This
                    FSP is not expected to have a material impact on Met-Ed's financial
                    statements.
 
 *SFAS
                    151,
“Inventory Costs - an amendment of ARB No. 43, Chapter 4”*
 
 In
                    November 2004,
                    the FASB issued SFAS 151 to clarify the accounting for abnormal
                    amounts of idle
                    facility expense, freight, handling costs and wasted material
                    (spoilage).
                    Previous guidance stated that in some circumstances these costs
                    may be “so
                    abnormal” that they would require treatment as current period costs. SFAS
                    151
                    requires abnormal amounts for these items to always be recorded
                    as current
                    period costs. In addition, this Statement requires that allocation
                    of fixed
                    production overheads to the cost of conversion be based on the
                    normal capacity
                    of the production facilities. The provisions of this statement
                    are effective for
                    inventory costs incurred by Met-Ed beginning January 1,
                    2006. Met-Ed is
                    currently evaluating this Standard and does not expect it to
                    have a material
                    impact on the financial statements.
 152
 
 *FSP
                  FAS 115-1,
                  "The Meaning of Other-Than-Temporary Impairment and its Application
                  to Certain
                  Investments"*
 
 In
                  September 2005,
                  the FASB finalized and renamed EITF 03-1 and 03-1-a to FSP FAS
                  115-1. FSP FAS
                  115-1 will (1) supersede Issue 03-1 and EITF topic No. D-44, "Recognition
                  of
                  Other Than Temporary Impairment upon the Planned Sale of a Security
                  Whose Cost
                  Exceeds Fair Value," (2) clarify that an investor should recognize
                  an impairment
                  loss no later than when the impairment is deemed other than temporary,
                  even if a
                  decision to sell has not been made, and (3) be effective for
                  other-than-temporary impairment and analyses conducted in periods
                  beginning
                  after September 15, 2005. The FASB expects to issue this
                  FSP in the fourth
                  quarter of 2005, which would require prospective application with
                  an effective
                  date for reporting periods beginning after December 15,
                  2005. Met-Ed is
                  currently evaluating this FSP and any impact on its investments.
  153
  **PENNSYLVANIA
                              ELECTRIC COMPANY****CONSOLIDATED
                              STATEMENTS OF INCOME AND COMPREHENSIVE INCOME****(Unaudited)****Three
                              Months Ended**
                          
                          **Nine
                              Months Ended****September
                              30,**
                          
                          **September
                              30,****2005**
                          
                          **2004**
                          
                          **2005**
                          
                          **2004*****(In
                              thousands)*****OPERATING
                              REVENUES**
                          
                          $
                          290,451
                          
                          $
                          254,339
                          
                          $
                          846,477
                          
                          $
                          752,986**OPERATING
                              EXPENSES AND TAXES:**Purchased
                              power
                          
                          
                          178,090
                          
                          
                          137,146
                          
                          
                          467,639
                          
                          
                          432,974Other
                              operating costs
                          
                          
                          66,417
                          
                          
                          37,100
                          
                          
                          183,024
                          
                          
                          122,988Provision
                              for
                              depreciation
                          
                          
                          12,736
                          
                          
                          12,281
                          
                          
                          37,721
                          
                          
                          35,229Amortization
                              of regulatory assets
                          
                          
                          12,627
                          
                          
                          11,759
                          
                          
                          38,930
                          
                          
                          39,130General
                              taxes
                          
                          
                          17,552
                          
                          
                          16,913
                          
                          
                          51,892
                          
                          
                          50,795Income
                              taxes
                          
                          
                          (3,101
                          )
                          
                          11,693
                          
                          
                          14,991
                          
                          
                          16,000Total
                              operating expenses and taxes
                          
                          
                          284,321
                          
                          
                          226,892
                          
                          
                          794,197
                          
                          
                          697,116**OPERATING
                              INCOME**
                          
                          
                          6,130
                          
                          
                          27,447
                          
                          
                          52,280
                          
                          
                          55,870**OTHER
                              INCOME (net of income taxes)**
                          
                          
                          1,057
                          
                          
                          1,300
                          
                          
                          1,477
                          
                          
                          1,663**NET
                              INTEREST CHARGES:**Interest
                              on
                              long-term debt
                          
                          
                          7,305
                          
                          
                          7,513
                          
                          
                          22,187
                          
                          
                          22,528Allowance
                              for
                              borrowed funds used during construction
                          
                          
                          (285
                          )
                          
                          (60
                          )
                          
                          (674
                          )
                          
                          (192
                          )Deferred
                              interest
                          
                          
                          -
                          
                          
                          -
                          
                          
                          -
                          
                          
                          190Other
                              interest
                              expense
                          
                          
                          2,536
                          
                          
                          3,058
                          
                          
                          7,392
                          
                          
                          8,063Net
                              interest
                              charges
                          
                          
                          9,556
                          
                          
                          10,511
                          
                          
                          28,905
                          
                          
                          30,589**NET
                              INCOME (LOSS)**
                          
                          
                          (2,369
                          )
                          
                          18,236
                          
                          
                          24,852
                          
                          
                          26,944**OTHER
                              COMPREHENSIVE INCOME (LOSS):**Unrealized
                              gain (loss) on derivative hedges
                          
                          
                          17
                          
                          
                          17
                          
                          
                          49
                          
                          
                          (618
                          )Unrealized
                              gain (loss) on available for sale securities
                          
                          
                          18
                          
                          
                          7
                          
                          
                          (3
                          )
                          
                          (3
                          )Other
                              comprehensive income (loss)
                          
                          
                          35
                          
                          
                          24
                          
                          
                          46
                          
                          
                          (621
                          )Income
                              tax
                              expense (benefit) related to other comprehensive income
                          
                          
                          20
                          
                          
                          (256
                          )
                          
                          20
                          
                          
                          (258
                          )Other
                              comprehensive income (loss), net of tax
                          
                          
                          15
                          
                          
                          280
                          
                          
                          26
                          
                          
                          (363
                          )**TOTAL
                              COMPREHENSIVE INCOME (LOSS)**
                          
                          $
                          (2,354
                          )
                          $
                          18,516
                          
                          $
                          24,878
                          
                          $
                          26,581The
                              preceding
                              Notes to Consolidated Financial Statements as they
                              relate to Pennsylvania
                              Electric Company are an integral part of these statements.
   154
  **PENNSYLVANIA
                              ELECTRIC COMPANY****CONSOLIDATED
                              BALANCE SHEETS****(Unaudited)****September
                              30,**
                          
                          **December
                              31,****2005**
                          
                          **2004*****(In
                              thousands)*****ASSETS****UTILITY
                              PLANT:**In
                              service
                          
                          $
                          2,004,891
                          
                          $
                          1,981,846Less
                              -
                              Accumulated provision for depreciation
                          
                          
                          772,818
                          
                          
                          776,9041,232,073
                          
                          
                          1,204,942Construction
                              work in progress
                          
                          
                          23,622
                          
                          
                          22,8161,255,695
                          
                          
                          1,227,758**OTHER
                              PROPERTY AND INVESTMENTS:**Nuclear
                              plant
                              decommissioning trusts
                          
                          
                          111,826
                          
                          
                          109,620Non-utility
                              generation trusts
                          
                          
                          97,473
                          
                          
                          95,991Long-term
                              notes receivable from associated companies
                          
                          
                          15,629
                          
                          
                          14,001Other
                          
                          
                          14,855
                          
                          
                          18,746239,783
                          
                          
                          238,358**CURRENT
                              ASSETS:**Cash
                              and cash
                              equivalents
                          
                          
                          35
                          
                          
                          36Notes
                              receivable from associated companies
                          
                          
                          -
                          
                          
                          7,352Receivables
                              -Customers
                              (less accumulated provisions of $4,095,000 and $4,712,000,respectively,
                              for uncollectible accounts)
                          
                          
                          120,580
                          
                          
                          121,112Associated
                              companies
                          
                          
                          6,339
                          
                          
                          97,528Other
                          
                          
                          7,369
                          
                          
                          12,778Prepayments
                              and other
                          
                          
                          15,818
                          
                          
                          7,198150,141
                          
                          
                          246,004**DEFERRED
                              CHARGES:**Goodwill
                          
                          
                          886,559
                          
                          
                          888,011Regulatory
                              assets
                          
                          
                          99,491
                          
                          
                          200,173Other
                          
                          
                          13,234
                          
                          
                          13,448999,284
                          
                          
                          1,101,632$
                          2,644,903
                          
                          $
                          2,813,752**CAPITALIZATION
                              AND LIABILITIES****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
                          
                          
                          1,206,358
                          
                          
                          1,205,948Accumulated
                              other comprehensive loss
                          
                          
                          (52,787
                          )
                          
                          (52,813
                          )Retained
                              earnings
                          
                          
                          38,920
                          
                          
                          46,068Total
                              common
                              stockholder's equity
                          
                          
                          1,298,303
                          
                          
                          1,305,015Long-term
                              debt
                              and other long-term obligations
                          
                          
                          478,954
                          
                          
                          481,8711,777,257
                          
                          
                          1,786,886**CURRENT
                              LIABILITIES:**Currently
                              payable long-term debt
                          
                          
                          4
                          
                          
                          8,248Short-term
                              borrowings -Associated
                              companies
                          
                          
                          114,749
                          
                          
                          241,496Other
                          
                          
                          75,000
                          
                          
                          -Accounts
                              payable -Associated
                              companies
                          
                          
                          30,456
                          
                          
                          56,154Other
                          
                          
                          35,987
                          
                          
                          25,960Accrued
                              taxes
                          
                          
                          19,234
                          
                          
                          7,999Accrued
                              interest
                          
                          
                          15,289
                          
                          
                          9,695Other
                          
                          
                          19,264
                          
                          
                          23,750309,983
                          
                          
                          373,302**NONCURRENT
                              LIABILITIES:**Power
                              purchase
                              contract loss liability
                          
                          
                          259,675
                          
                          
                          382,548Retirement
                              benefits
                          
                          
                          121,251
                          
                          
                          118,247Asset
                              retirement obligation
                          
                          
                          69,608
                          
                          
                          66,443Accumulated
                              deferred income taxes
                          
                          
                          56,029
                          
                          
                          37,318Other
                          
                          
                          51,100
                          
                          
                          49,008557,663
                          
                          
                          653,564**COMMITMENTS
                              AND CONTINGENCIES (Note 13)**$
                          2,644,903
                          
                          $
                          2,813,752The
                              preceding
                              Notes to Consolidated Financial Statements as they
                              relate to Pennsylvania
                              Electric Company are an integral part of these
                              balance
                              sheets.
   155
  **PENNSYLVANIA
                              ELECTRIC COMPANY****CONSOLIDATED
                              STATEMENTS OF CASH FLOWS****(Unaudited)****Three
                              Months Ended**
                          
                          **Nine
                              Months Ended****September
                              30,**
                          
                          **September
                              30,****2005**
                          
                          **2004**
                          
                          **2005**
                          
                          **2004*****(In
                              thousands)*****CASH
                              FLOWS FROM OPERATING ACTIVITIES:**Net
                              income
                              (loss)
                          
                          $
                          (2,369
                          )
                          $
                          18,236
                          
                          $
                          24,852
                          
                          $
                          26,944Adjustments
                              to
                              reconcile net income (loss) to net cash fromoperating
                              activities -Provision
                              for
                              depreciation
                          
                          
                          12,736
                          
                          
                          12,281
                          
                          
                          37,721
                          
                          
                          35,229Amortization
                              of regulatory assets
                          
                          
                          12,627
                          
                          
                          11,759
                          
                          
                          38,930
                          
                          
                          39,130Deferred
                              costs
                              recoverable as regulatory assets
                          
                          
                          (5,355
                          )
                          
                          (25,618
                          )
                          
                          (41,301
                          )
                          
                          (62,122
                          )Deferred
                              income taxes and investment tax credits, net
                          
                          
                          (5,412
                          )
                          
                          28,574
                          
                          
                          (2,765
                          )
                          
                          30,308Accrued
                              retirement benefit obligations
                          
                          
                          1,100
                          
                          
                          1,164
                          
                          
                          3,005
                          
                          
                          4,805Accrued
                              compensation, net
                          
                          
                          691
                          
                          
                          894
                          
                          
                          (1,695
                          )
                          
                          2,271Pension
                              trust
                              contribution
                          
                          
                          -
                          
                          
                          (50,281
                          )
                          
                          -
                          
                          
                          (50,281
                          )Decrease
                              (increase) in operating assets -Receivables
                          
                          
                          17,528
                          
                          
                          (17,689
                          )
                          
                          97,130
                          
                          
                          35,806Prepayments and other current assets
                          
                          
                          13,487
                          
                          
                          9,703
                          
                          
                          (8,620
                          )
                          
                          (25,247
                          )Increase
                              (decrease) in operating liabilities -Accounts payable
                          
                          
                          4,662
                          
                          
                          (23,255
                          )
                          
                          (15,671
                          )
                          
                          (38,015
                          )Accrued taxes
                          
                          
                          507
                          
                          
                          2
                          
                          
                          11,235
                          
                          
                          (7,572
                          )Accrued interest
                          
                          
                          5,628
                          
                          
                          5,605
                          
                          
                          5,594
                          
                          
                          2,856Other
                          
                          
                          (1,460
                          )
                          
                          562
                          
                          
                          2,905
                          
                          
                          24,851Net cash provided from (used for) operating
                              activities
                          
                          
                          54,370
                          
                          
                          (28,063
                          )
                          
                          151,320
                          
                          
                          18,963**CASH
                              FLOWS FROM FINANCING ACTIVITIES:**New
                              Financing
                              -Long-term
                              debt
                          
                          
                          -
                          
                          
                          -
                          
                          
                          -
                          
                          
                          150,000Short-term
                              borrowings, net
                          
                          
                          -
                          
                          
                          158,282
                          
                          
                          -
                          
                          
                          165,918Redemptions
                              and Repayments -Long-term
                              debt
                          
                          
                          (8,013
                          )
                          
                          (103,241
                          )
                          
                          (11,534
                          )
                          
                          (228,453
                          )Short-term
                              borrowings, net
                          
                          
                          (15,139
                          )
                          
                          -
                          
                          
                          (51,747
                          )
                          
                          -Dividend
                              Payments -Common
                              stock
                          
                          
                          (2,000
                          )
                          
                          (3,000
                          )
                          
                          (32,000
                          )
                          
                          (8,000
                          )Net
                              cash provided from (used for) financing activities
                          
                          
                          (25,152
                          )
                          
                          52,041
                          
                          
                          (95,281
                          )
                          
                          79,465**CASH
                              FLOWS FROM INVESTING ACTIVITIES:**Property
                              additions
                          
                          
                          (27,997
                          )
                          
                          (10,192
                          )
                          
                          (61,680
                          )
                          
                          (33,428
                          )Non-utility
                              generation trust contribution
                          
                          
                          -
                          
                          
                          -
                          
                          
                          -
                          
                          
                          (50,614
                          )Loan
                              repayments from (loans to) associated companies, net
                          
                          
                          (1,287
                          )
                          
                          (3,124
                          )
                          
                          5,724
                          
                          
                          (3,144
                          )Other,
                              net
                          
                          
                          66
                          
                          
                          (10,662
                          )
                          
                          (84
                          )
                          
                          (11,242
                          )Net
                              cash
                              used for investing activities
                          
                          
                          (29,218
                          )
                          
                          (23,978
                          )
                          
                          (56,040
                          )
                          
                          (98,428
                          )Net
                              change in
                              cash and cash equivalents
                          
                          
                          -
                          
                          
                          -
                          
                          
                          (1
                          )
                          
                          -Cash
                              and cash
                              equivalents at beginning of period
                          
                          
                          35
                          
                          
                          36
                          
                          
                          36
                          
                          
                          36Cash
                              and cash
                              equivalents at end of period
                          
                          $
                          35
                          
                          $
                          36
                          
                          $
                          35
                          
                          $
                          36The
                              preceding
                              Notes to Consolidated Financial Statements as they
                              relate to Pennsylvania
                              Electric Company are an integral part of these statements.
 
 156
  ***Report
              of Independent Registered Public Accounting Firm***
 
 
 
 
 
 
 
 
 
 To
              the Stockholders
              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, 2005, and the related consolidated
              statements of income and comprehensive income and cash flows for each
              of the
              three-month and nine-month periods ended September 30, 2005
              and 2004. 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
              previously
              audited, in accordance with the standards of the Public Company Accounting
              Oversight Board (United States), the consolidated balance sheet as
              of
              December 31, 2004, and the related consolidated statements of
              income,
              capitalization, common stockholder’s 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,
              2004 and the effectiveness of the Company’s internal control over financial
              reporting as of December 31, 2004; 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) 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 March 7, 2005, 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 information as of December 31,
              2004, is fairly stated in all material respects in relation to the
              consolidated
              balance sheet from which it has been derived.
 
 
 
 
 PricewaterhouseCoopers
              LLP
 Cleveland,
              Ohio
 November
              1,
              2005
 
 157
 **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.
              Penelec has unbundled the price for electricity into its component
              elements -
              including generation, transmission, distribution and transition
              charges.
 
 **Results
              of Operations**
 
 Penelec
              recognized
              a net loss of $2 million in the third quarter of 2005, compared to
              $18 million
              in net income in the third quarter of 2004. During the first nine months
              of
              2005, net income decreased to $25 million compared to $27 million in
              the first
              nine months of 2004. The decrease in both periods resulted from higher
              purchased
              power and other operating costs, partially offset by higher operating
              revenues
              and lower income taxes.
 
 Operating
              revenues
              increased by $36 million in the third quarter and $93 million in the
              first nine
              months of 2005 compared to the same periods of 2004. Increases in both
              periods
              were due to higher retail generation revenues in all sectors ($14 million
              for
              the quarter and $23 million for the first nine months). The increases
              in retail
              generation KWH sales in both periods of 2005 were mainly due to the
              warmer
              weather in 2005 compared to 2004. While the higher generation sales
              in the third
              quarter were offset by slightly lower composite unit prices, overall
              higher
              composite unit prices - especially in the industrial sector - for the
              nine-month
              period further contributed to the increase in generation revenues.
 
 Distribution
              revenues increased by $4 million in the third quarter and by $6 million
              in the
              first nine months of 2005 compared to the same periods of 2004. Increases
              in
              both periods were due to higher KWH deliveries partially offset by
              lower unit
              prices. Also contributing to higher operating revenues was an increase
              in
              transmission revenues of $18 million in the third quarter and $61 million
              in the
              first nine months of 2005. These increases were due to a change in
              the power
              supply agreement with FES in the second quarter of 2004. This change
              also
              resulted in higher transmission expenses as discussed further
              below.
 
 Changes
              in KWH
              sales by customer class in the three months and nine months ended
              September 30, 2005 from the corresponding periods of 2004 are
              summarized in
              the following table:
 **Three**
                  
                  **Nine****Changes
                      in KWH Sales**
                  
                  **Months**
                  
                  **Months****Increase
                      (Decrease)**Retail
                      Electric Generation:Residential
                  
                  
                  8.8
                  %
                  
                  4.2
                  %Commercial
                  
                  
                  7.0
                  %
                  
                  4.3
                  %Industrial
                  
                  
                  17.0
                  %
                  
                  7.3
                  %**Total
                      Retail Electric Generation Sales**
                  
                  
                  **10.2**
                  **%**
                  
                  **5.1**
                  **%**Distribution
                      Deliveries:Residential
                  
                  
                  8.7
                  %
                  
                  4.1
                  %Commercial
                  
                  
                  6.6
                  %
                  
                  4.1
                  %Industrial
                  
                  
                  8.3
                  %
                  
                  5.2
                  %**Total
                      Distribution Deliveries**
                  
                  
                  **7.8**
                  **%**
                  
                  **4.5**
                  **%**
 
 
 158
 *Operating
              Expenses and Taxes*
  Total
              operating
              expenses and taxes increased by $57 million in the third quarter and
              $97 million
              in the first nine months of 2005 compared with the same periods in
              2004. The
              following table presents changes from the prior year by expense category:
 **Three**
                  
                  **Nine****Operating
                      Expenses and Taxes - Changes**
                  
                  **Months**
                  
                  **Months*****(In
                      millions)*****Increase
                      (Decrease)**Purchased
                      power costs
                  
                  $
                  41
                  
                  $
                  35Other
                      operating costs
                  
                  
                  29
                  
                  
                  60Provision
                      for
                      depreciation
                  
                  
                  -
                  
                  
                  2Amortization
                      of regulatory assets
                  
                  
                  1
                  
                  
                  -General
                      taxes
                  
                  
                  1
                  
                  
                  1Income
                      taxes
                  
                  
                  (15
                  )
                  
                  (1
                  )**Net
                      increase in operating expenses and taxes**
                  
                  $
                  57
                  
                  $
                  97
 
 Purchased
              power
              costs increased by $41 million or 29.9% in the third quarter and $35
              million or
              8.0% in the first nine months of 2005 compared to the same periods
              of 2004. The
              increase in the third quarter of 2005 is due to increased KWH purchased
              to meet
              increased retail generation sales requirements, and higher unit costs.
              Third-party power purchases and NUG costs increased $48 million and
              $20 million,
              respectively, in the third quarter of 2005, partially offset by reduced
              purchased power from FES of $27 million. The increase in the first
              nine months
              is due to increased KWH purchased to meet sales requirements partially
              offset by
              lower unit costs. Increases from third-party power purchases and NUG
              costs of
              $81 million and $21 million, respectively, in the first nine months
              of 2005,
              were partially offset by reduced purchased power from FES of $67
              million.
 
 Other
              operating
              costs increased by $29 million in the third quarter and $60 million
              in the first
              nine months of 2005 compared to same periods in 2004. The increases
              in both
              periods were primarily due to increased transmission expenses in 2005
              as a
              result of the change in the power supply agreement with FES referred
              to above.
              The increased transmission expenses were partially offset by reduced
              labor costs
              that were charged to capital projects. Income taxes decreased in the
              third
              quarter of 2005 due to lower pre-tax income compared to the third quarter
              of
              2004.
 
 **Capital
              Resources and Liquidity**
 
 Penelec’s
              cash
              requirements for the remainder of 2005 for operating expenses, construction
              expenditures and scheduled debt maturities are expected to be met with
              cash from
              operations.
 
 *Changes
              in Cash
              Position*
  As
              of September 30,
              2005, Penelec had $35,000 of cash and cash equivalents compared with
              $36,000 as
              of December 31, 2004. The major sources for changes in these
              balances are
              summarized below.
 
 *Cash
              Flows From
              Operating Activities*
 
 Net
              cash provided
              from (used for) operating activities in the third quarter and first
              nine months
              of 2005, compared with the corresponding periods in 2004, are summarized
              as
              follows:
 **Three
                      Months Ended**
                  
                  **Nine
                      Months Ended****September
                      30,**
                  
                  **September
                      30,****Operating
                      Cash Flows**
                  
                  **2005**
                  
                  **2004**
                  
                  **2005**
                  
                  **2004*****(In
                      millions)***Cash
                      earnings
                      (1)
                  
                  $
                  14
                  
                  $
                  27
                  
                  $
                  59
                  
                  $
                  56Pension
                      trust
                      contribution (2)
                  
                  
                  -
                  
                  
                  (30
                  )
                  
                  -
                  
                  
                  (30
                  )Working
                      capital and other
                  
                  
                  40
                  
                  
                  (25
                  )
                  
                  92
                  
                  
                  (7
                  )Total
                      cash
                      flows from operating activities
                  
                  $
                  54
                  
                  $
                  (28
                  )
                  $
                  151
                  
                  $
                  19
 (1)
            Cash
            earnings is a non-GAAP measure (see reconciliation below).
 (2)
            Pension trust contribution net of $20 million of income tax
            benefits.
 
 159
 
 Cash
              earnings, as
              disclosed 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. The following table
              reconciles
              cash earnings with net income.
 **Three
                      Months Ended**
                  
                  **Nine
                      Months Ended****September
                      30,**
                  
                  **September
                      30,****Reconciliation
                      of Cash Earnings**
                  
                  **2005**
                  
                  **2004**
                  
                  **2005**
                  
                  **2004*****(In
                      millions)***Net
                      income
                      (loss) (GAAP)
                  
                  $
                  (2
                  )
                  $
                  18
                  
                  $
                  25
                  
                  $
                  27Non-cash
                      charges (credits):Provision
                      for
                      depreciation
                  
                  
                  13
                  
                  
                  12
                  
                  
                  38
                  
                  
                  35Amortization
                      of regulatory assets
                  
                  
                  12
                  
                  
                  12
                  
                  
                  39
                  
                  
                  39Deferred
                      costs recoverable as regulatory assets
                  
                  
                  (5
                  )
                  
                  (26
                  )
                  
                  (41
                  )
                  
                  (62
                  )Deferred
                      income taxes and investment tax credits, net
                  
                  
                  (6
                  )
                  
                  9
                  
                  
                  (3
                  )
                  
                  10Other
                      non-cash items
                  
                  
                  2
                  
                  
                  2
                  
                  
                  1
                  
                  
                  7Cash
                      earnings
                      (Non-GAAP)
                  
                  $
                  14
                  
                  $
                  27
                  
                  $
                  59
                  
                  $
                  56
 
 Net
              cash from
              operating activities increased $82 million in the third quarter of
              2005,
              compared with the third quarter of 2004, due to a $66 million increase
              from
              changes in working capital, an absence of a $30 million after-tax voluntary
              pension contribution made in the third quarter of 2004, and partially
              offset by
              a $13 million decrease in cash earnings as described above under “Results of
              Operations”. The increase in working capital primarily reflects net changes in
              accounts receivable and accounts payable to associated companies of
              $42 million
              and a $22 million increase in purchase power accounts payable.
 
 Net
              cash from
              operating activities increased $132 million in the first nine months
              of 2005,
              compared with the same period of 2004, due to a $100 million increase
              from
              changes in working capital, an absence of the $30 million after-tax
              voluntary
              pension contribution, and a $3 million increase in cash earnings as
              described
              above under “Results of Operations”. The increase in working capital primarily
              reflects changes in accounts receivable to associated companies of
              $61 million,
              $30 million increase in purchase power and other accounts payable,
              and $19
              million change in accrued taxes, partially offset by changes in customer
              deposits.
 
 *Cash
              Flows From
              Financing Activities*
  Net
              cash used for
              financing activities was $25 million in the third quarter of 2005 compared
              to
              net cash provided from financing activities of $52 million in the third
              quarter
              of 2004. The net change reflects a $1 million decrease in common stock
              dividends
              to FirstEnergy and a $173 million increase in repayments of short-term
              borrowings, offset by a $95 million decrease in debt redemptions.
 
 Net
              cash used for
              financing activities was $95 million for the first nine months of 2005
              compared
              to net cash provided from financing activities of $79 million in the
              first nine
              months of 2004. The net change of $174 million reflects $150 million
              of
              long-term debt financing in 2004, a $24 million increase in common
              stock
              dividends to FirstEnergy in 2005 and a $218 million increase in repayments
              of
              short-term borrowings, offset by a $217 million decrease in debt
              redemptions.
 
 Penelec
              had
              approximately $35,000 of cash and temporary investments (which included
              short-term notes receivable from associated companies) and approximately
              $190
              million of short-term indebtedness as of September 30, 2005.
              Penelec has
              authorization from the SEC to incur short-term debt of up to $250 million
              (including the utility money pool). 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, 2005, Penelec had the capability
              to issue
              $18 million of additional senior notes based upon FMB collateral. Penelec
              has no
              restrictions on the issuance of preferred stock.
 
 Penelec
              Funding LLC
              (Penelec Funding), a wholly owned subsidiary of Penelec, is a limited
              liability
              company whose borrowings are secured by customer accounts receivable
              purchased
              from Penelec. Penelec Funding can borrow up to $75 million under a
              receivables
              financing arrangement. 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. On July 15,
              2005,
              the facility was renewed until June 29, 2006. The facility was
              undrawn as
              of September 30, 2005. The annual facility fee is 0.25% on the
              entire
              finance limit.
 160
  On
              June 14,
              2005, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI,
              as Borrowers, entered into a syndicated $2 billion five-year revolving
              credit
              facility. Borrowings under the facility are available to each Borrower
              separately and mature on the earlier of 364 days from the date of borrowing
              or
              the commitment termination date, as the same may be extended. Penelec's
              borrowing limit under the facility is $250 million.
 
 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 third
              quarter of
              2005 was 3.5%.
 
 On
              July 18,
              2005, Moody’s revised its rating outlook on FirstEnergy and its subsidiaries to
              positive from stable. Moody’s stated that the revision to FirstEnergy’s outlook
              resulted from steady financial improvement and steps taken by management
              to
              improve operations, including the stabilization of its nuclear operations.
              Moody’s further stated that the revision in their outlook recognized
              management’s regional strategy of focusing on its core utility businesses and
              the improvement in FirstEnergy’s credit profile stemming from the application of
              free cash flow toward debt reduction. Moody’s noted that a ratings upgrade could
              be considered if FirstEnergy continues to achieve planned improvements
              in its
              operations and balance sheet.
 
 On
              October 3,
              2005, S&P raised its corporate credit rating on FirstEnergy and the EUOC to
              'BBB' from 'BBB-'. At the same time, S&P raised the senior unsecured ratings
              at the holding company to 'BBB-' from 'BB+' and each of the EUOC by
              one notch
              above the previous rating. S&P noted that the upgrade followed the
              continuation of a good operating track record, specifically for the
              nuclear
              fleet through the third quarter 2005. S&P also stated that FirstEnergy’s
              rating reflects the benefits of supportive regulation, low-cost base
              load
              generation fleet, low-risk transmission and distribution operations
              and rate
              certainty in Ohio. FirstEnergy’s ability to consistently generate free cash
              flow, good liquidity, and an improving financial profile were also
              noted as
              strengths.
 
 Penelec’s
              access to
              capital markets and costs of financing are influenced by the ratings
              of its
              securities and the securities of FirstEnergy. The ratings outlook from
              S&P
              and Fitch on all securities is stable. Moody’s outlook on all securities is
              positive.
 
 *Cash
              Flows From
              Investing Activities*
  Cash
              used for
              investing activities was $29 million in the third quarter of 2005 compared
              to
              $24 million in the third quarter of 2004. The increase was primarily
              due to
              higher property additions, partially offset by lower loan repayments
              from
              associated companies and the absence in 2005 of an $11 million capital
              transfer
              from FESC that took place in September 2004. Cash used for investing
              activities
              was $56 million in the first nine months of 2005 compared to $98 million
              in the
              first nine months of 2004. The decrease was primarily due to a $51
              million
              repayment to the NUG trust fund in 2004, increased loans from associated
              companies, and the $11 million capital transfer from above, partially
              offset by
              higher property additions in 2005. Capital expenditures for property
              additions
              primarily support Penelec’s energy delivery operations.
 
 Penelec’s
              capital
              spending for the period 2005-2007 is expected to be about $272 million
              for
              property additions and improvements, of which about $91 million applies
              to 2005.
              In the last quarter of 2005, capital requirements for property additions
              are
              expected to be about $26 million. Penelec has no additional requirements
              for
              maturing long-term debt during the remainder of 2005. These cash requirements
              are expected to be satisfied from internal cash and short-term credit
              arrangements.
 
 **Market
              Risk Information**
  Penelec
              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 management oversight to risk management
              activities.
 
 *Commodity
              Price
              Risk*
 
 Penelec
              is exposed
              to price risk primarily due to fluctuating electricity and natural
              gas prices.
              To manage the volatility relating to these exposures, it uses a variety
              of
              non-derivative and derivative instruments, including options and futures
              contracts. The derivatives are used for hedging purposes. Penelec’s non-hedge
              derivative contracts represent non-trading positions that do not qualify
              for
              hedge treatment under SFAS 133. As of September 30, 2005, Penelec’s
              commodity derivatives contract was an embedded option with a fair value
              of $14
              million. A decrease of $1 million in the value of this asset was recorded
              in the
              first nine months of 2005 as a decrease in regulatory liabilities,
              and
              therefore, had no impact on net income.
 161
 The
              valuation of
              derivative commodity 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 valuation of derivative contracts as of
              September 30, 2005 are summarized by year in the following
              table:
 **Sources
                      of Information****-****Fair
                      Value by Contract Year**
                  
                  
                  
                  **2005**(1)
                  
                  **2006**
                  
                  **2007**
                  
                  **2008**
                  
                  **2009**
                  
                  **Thereafter**
                  
                  **Total**Prices
                      based
                      on external sources(2)
                  
                  
                  
                  
                  $
                  3
                  
                  $
                  3
                  
                  $
                  2
                  
                  $
                  -
                  
                  $
                  -
                  
                  $
                  -
                  
                  $
                  8Prices
                      based
                      on models
                  
                  
                  
                  
                  
                  -
                  
                  
                  -
                  
                  
                  -
                  
                  
                  2
                  
                  
                  2
                  
                  
                  2
                  
                  
                  6Total
                  
                  
                  
                  
                  $
                  3
                  
                  $
                  3
                  
                  $
                  2
                  
                  $
                  2
                  
                  $
                  2
                  
                  $
                  2
                  
                  $
                  14(1)For
                      the
                      last quarter of 2005.
                    (2)Broker
                      quote sheets.
 
 Penelec
              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 both its trading and nontrading derivative instruments would not
              have had a
              material effect on its consolidated financial position or cash flows
              as of
              September 30, 2005.
 
 *Equity
              Price
              Risk*
 
 Included
              in nuclear
              decommissioning trusts are marketable equity securities carried at
              their current
              fair value of approximately $61 million and $60 million as of September 30,
              2005 and December 31, 2004, respectively. A hypothetical 10%
              decrease in
              prices quoted by stock exchanges would result in a $6 million reduction
              in fair
              value as of September 30, 2005.
 
 **Regulatory
              Matters**
 
 Regulatory
              assets
              are costs which have been authorized by the PPUC and the FERC for recovery
              from
              customers in future periods and, without such authorization, would
              have been
              charged to income when incurred. Penelec's regulatory assets as of
              September 30, 2005 and December 31, 2004 were $99 million
              and $200
              million, respectively.
 
 In
              accordance with
              PPUC directives, Met-Ed and Penelec have been negotiating with interested
              parties in an attempt to resolve the merger savings issues that are
              the subject
              of remand from the Commonwealth Court. Met-Ed’s and Penelec’s combined portion
              of total merger savings is estimated to be approximately $31.5 million.
              On
              April 13, 2005, the Commonwealth Court issued an interim order
              in the
              remand proceeding that the parties should report the status of the
              negotiations
              to the PPUC with a copy to the ALJ. The parties exchanged settlement
              proposals
              in May and June 2005 and continue to have settlement discussions.
 
 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 judge, 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.
 
 Penelec
              purchases a
              portion of its PLR requirements from FES through a wholesale power
              sales
              agreement. The PLR sale is automatically extended for each successive
              calendar
              year unless either party elects to cancel the agreement by November 1
              of
              the preceding year. Under the terms of the wholesale agreement, FES
              retains the
              supply obligation and the supply profit and loss risk, for the portion
              of power
              supply requirements not self-supplied by Penelec under its NUG contracts
              and
              other power contracts with nonaffiliated third party suppliers. This
              arrangement
              reduces Penelec's exposure to high wholesale power prices by providing
              power at
              a fixed price for its uncommitted PLR energy costs during the term
              of the
              agreement with FES. Penelec is authorized to defer differences between
              NUG
              contract costs and current market prices. On
              November 1,
              2005, FES and the other parties to the wholesale power agreement amended
              the
              agreement to provide FES the right over the next year to terminate
              the agreement
              at any time upon 60 days notice.If
              the wholesale
              power agreement were terminated, Met-Ed and Penelec would need to satisfy
              the
              applicable portion of their PLR obligations from other sources at prevailing
              prices, which are likely to be higher than the current price charged
              by FES
              under the agreement and, as a result, Met-Ed’s and Penelec’s purchased power
              costs could materially increase.
 162
 On
              January 12,
              2005, Penelec filed a request with the PPUC to defer transmission-related
              costs
              beginning January 1, 2005, estimated to be approximately $4
              million per
              month. The OCA, OSBA, OTS, MEIUG, PICA, Allegheny Electric Cooperative
              and
              Pennsylvania Rural Electric Association have all intervened in the
              case. To date
              no hearing schedule has been established, and Penelec has not yet implemented
              deferral accounting for these costs.
 
 On
              January 31,
              2005, certain PJM transmission owners made three filings pursuant to
              a
              settlement agreement previously approved by the FERC. Penelec was party
              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. Second, the FERC approved the proposed Schedule
              12 rate
              harmonization. Third, the FERC accepted the proposed formula rate,
              subject to
              referral and hearing procedures. On June 30, 2005, the PJM transmission
              owners filed a request for rehearing of the May 31, 2005 order.
              The rate
              design and formula rate filings continue to be litigated before the
              FERC. The
              outcome of these two cases cannot be predicted.
 
 See
              Note 14 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 estimate 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.
 
 FirstEnergy
              plans
              to issue a report regarding its response to air emission requirements.
              FirstEnergy expects to complete the report by December 1,
              2005.
 
 See
              Note 13(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 Penelec's normal business operations pending against Penelec.
              The
              other material items not otherwise discussed above are described
              below.
 
 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 concludes, 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 website (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 also is proceeding
              with the
              implementation of the recommendations regarding enhancements to regional
              reliability 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, and therefore FirstEnergy has not accrued a liability as
              of
              September 30, 2005 for any expenditures in excess of those actually
              incurred through that date. 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
              that could
              require additional, material expenditures. Finally, the PUCO is continuing
              to
              review FirstEnergy’s filing that addressed upgrades to control room computer
              hardware and software and enhancements to the training of control room
              operators, before determining the next steps, if any, in the
              proceeding.
  163
 One
              complaint was
              filed on August 25, 2004 against FirstEnergy in the New York State
              Supreme
              Court. In this case, several plaintiffs in the New York City metropolitan
              area
              allege that they suffered damages as a result of the August 14,
              2003 power
              outages. None of the plaintiffs are customers of any FirstEnergy affiliate.
              FirstEnergy's motion to dismiss the case was granted on September 26,
              2005.
              Additionally, FirstEnergy Corp. was named in a complaint filed in Michigan
              State
              Court by an individual who is not a customer of any FirstEnergy company.
              A
              responsive pleading to this matter is not due until on or about December
              1,
              2005. No estimate of potential liability has been undertaken in this
              matter.
 
 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.
 
 See
              Note 13(C) to
              the consolidated financial statements for further details and a complete
              discussion of other legal proceedings.
 
 **New
              Accounting Standards and Interpretations**
 
 *EITF
              Issue
              04-13, "Accounting for Purchases and Sales of Inventory with the Same
              Counterparty"*
  In
              September 2005,
              the EITF reached a final consensus on Issue 04-13 concluding that two
              or more
              legally separate exchange transactions with the same counterparty should
              be
              combined and considered as a single arrangement for purposes of applying
              APB 29,
              when the transactions were entered into "in contemplation" of one another.
              If
              two transactions are combined and considered a single arrangement,
              the EITF
              reached a consensus that an exchange of inventory should be accounted
              for at
              fair value. Although electric power is not capable of being held in
              inventory,
              there is no substantive conceptual distinction between exchanges involving
              power
              and other storable inventory. Therefore, Penelec will adopt this EITF
              effective
              for new arrangements entered into, or modifications or renewals of
              existing
              arrangements, in interim or annual periods beginning after March 15,
              2006.
 
 *EITF
                        Issue No. 05-6, "Determining the Amortization Period for
                        Leasehold
                        Improvements Purchased after Lease Inception or Acquired
                        in a Business
                        Combination"*
  In
              June 2005, the
              EITF reached a consensus on the application guidance for Issue 05-6.
              EITF 05-6
              addresses the amortization period for leasehold improvements that were
              either
              acquired in a business combination or placed in service significantly
              after and
              not contemplated at or near the beginning of the initial lease term.
              For
              leasehold improvements acquired in a business combination, the amortization
              period is the shorter of the useful life of the assets or a term that
              includes
              required lease periods and renewals that are deemed to be reasonably
              assured at
              the date of acquisition. Leasehold improvements that are placed in
              service
              significantly after and not contemplated at or near the beginning of
              the lease
              term should be amortized over the shorter of the useful life of the
              assets or a
              term that includes required lease periods and renewals that are deemed
              to be
              reasonably assured at the date the leasehold improvements are purchased.
              This
              EITF was effective July 1, 2005 and is consistent with Penelec's
              current
              accounting.
 164
  *FIN
              47,
“Accounting for Conditional Asset Retirement Obligations - an interpretation
              of
              FASB Statement No. 143”*
 
 On
              March 30,
              2005, the FASB issued FIN 47 to clarify the scope and timing of liability
              recognition for conditional asset retirement obligations. Under this
              interpretation, companies are required to recognize a liability for
              the fair
              value of an asset retirement obligation that is conditional on a future
              event,
              if the fair value of the liability can be reasonably estimated. In
              instances
              where there is insufficient information to estimate the liability,
              the
              obligation is to be recognized in the first period in which sufficient
              information becomes available to estimate its fair value. If the fair
              value
              cannot be reasonably estimated, that fact and the reasons why must
              be disclosed.
              This Interpretation is effective for Penelec in the fourth quarter
              of 2005.
              Penelec is currently evaluating the effect this Interpretation will
              have on its
              financial statements.
 
 *SFAS
                        154
                        - “Accounting Changes and Error Corrections - a replacement
                        of APB Opinion
                        No. 20 and FASB Statement No.
                        3”*
 
 In
              May 2005, the
              FASB issued SFAS 154 to change the requirements for accounting and
              reporting a
              change in accounting principle. It applies to all voluntary changes
              in
              accounting principle and to changes required by an accounting pronouncement
              when
              that pronouncement does not include specific transition provisions.
              This
              Statement requires retrospective application to prior periods’ financial
              statements of changes in accounting principle, unless it is impracticable
              to
              determine either the period-specific effects or the cumulative effect
              of the
              change. In those instances, this Statement requires that the new accounting
              principle be applied to the balances of assets and liabilities as of
              the
              beginning of the earliest period for which retrospective application
              is
              practicable and that a corresponding adjustment be made to the opening
              balance
              of retained earnings (or other appropriate components of equity or
              net assets in
              the statement of financial position) for that period rather than being
              reported
              in the Consolidated Statements of Income. This Statement also requires
              that a
              change in depreciation, amortization, or depletion method for long-lived,
              nonfinancial assets be accounted for as a change in accounting estimate
              affected
              by a change in accounting principle. The provisions of this Statement
              are
              effective for accounting changes and corrections of errors made in
              fiscal years
              beginning after December 15, 2005. Penelec will adopt this Statement
              effective January 1, 2006.
 
 *SFAS
                        153,
                        “Exchanges of Nonmonetary Assets - an amendment of APB Opinion
                        No.
                        29”*
 
 In
              December 2004,
              the FASB issued SFAS 153 amending APB 29, which was based on the principle
              that
              nonmonetary assets should be measured based on the fair value of the
              assets
              exchanged. The guidance in APB 29 included certain exceptions to that
              principle.
              SFAS 153 eliminates the exception from fair value measurement for nonmonetary
              exchanges of similar productive assets and replaces it with an exception
              for
              exchanges that do not have commercial substance. This Statement specifies
              that a
              nonmonetary exchange has commercial substance if the future cash flows
              of the
              entity are expected to change significantly as a result of the exchange.
              The
              provisions of this Statement are effective January 1, 2006 for
              Penelec.
              This FSP is not expected to have a material impact on Penelec's financial
              statements.
 
 *SFAS
              151,
“Inventory Costs - an amendment of ARB No. 43, Chapter 4”*
 
 In
              November 2004,
              the FASB issued SFAS 151 to clarify the accounting for abnormal amounts
              of idle
              facility expense, freight, handling costs and wasted material (spoilage).
              Previous guidance stated that in some circumstances these costs may
              be “so
              abnormal” that they would require treatment as current period costs. SFAS 151
              requires abnormal amounts for these items to always be recorded as
              current
              period costs. In addition, this Statement requires that allocation
              of fixed
              production overheads to the cost of conversion be based on the normal
              capacity
              of the production facilities. The provisions of this statement are
              effective for
              inventory costs incurred by Penelec beginning January 1, 2006.
              Penelec is
              currently evaluating this Standard and does not expect it to have a
              material
              impact on the financial statements.
 165
 *FSP
              FAS 115-1,
              "The Meaning of Other-Than-Temporary Impairment and its Application
              to Certain
              Investments"*
 
 In
              September 2005,
              the FASB finalized and renamed EITF 03-1 and 03-1-a to FSP FAS 115-1.
              FSP FAS
              115-1 will (1) supersede Issue 03-1 and EITF topic No. D-44, "Recognition
              of
              Other Than Temporary Impairment upon the Planned Sale of a Security
              Whose Cost
              Exceeds Fair Value," (2) clarify that an investor should recognize
              an impairment
              loss no later than when the impairment is deemed other than temporary,
              even if a
              decision to sell has not been made, and (3) be effective for
              other-than-temporary impairment and analyses conducted in periods beginning
              after September 15, 2005. The FASB expects to issue this FSP
              in the fourth
              quarter of 2005, which would require prospective application with an
              effective
              date for reporting periods beginning after December 15, 2005. Penelec
              is
              currently evaluating this FSP and any impact on its
              investments.
 166
  **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,
              as defined in
              the Securities Exchange Act of 1934 Rules 13a-15(e) and 15d-15(e),
              as of the end
              of the date covered by the report. Based on that evaluation, those
              officers have
              concluded that the registrant's disclosure controls and procedures
              are effective
              in timely alerting them to any information relating to the registrants
              and their
              consolidated subsidiaries that is required to be included in the registrants’
              periodic reports and in ensuring that information required in the reports
              filed
              under the Securities Exchange Act of 1934 is recorded, processed, summarized
              and
              reported within the time period specified by the SEC's rules and
              forms.
 
 **(b)**  **CHANGES
              IN
              INTERNAL CONTROLS**
 
 During
              the quarter
              ended September 30, 2005, there were no 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.
 167
  ***PART
              II. OTHER INFORMATION***
 
 **ITEM
              1.**  **LEGAL
              PROCEEDINGS**
  Information
              required for Part II, Item 1 is incorporated by reference to the discussions
              in
              Notes 13 and 14 to the Consolidated Financial Statements in Part I,
              Item 1 of
              this Form 10-Q.
  **ITEM
              2.**  **CHANGES
              IN
              SECURITIES, USE OF PROCEEDS AND ISSUER PURCHASES OF EQUITY
              SECURITIES**
 
 **(e)**  **FirstEnergy**
 
 The
              table below
              includes information on a monthly basis regarding purchases made by
              FirstEnergy
              of its common stock.
 **Maximum
                      Number****(or
                      Approximate****Total
                      Number of**
                  
                  **Dollar
                      Value) of****Shares
                      Purchased**
                  
                  **Shares
                      that May****Total
                      Number**
                  
                  
                  
                  **As
                      Part of Publicly**
                  
                  **Yet
                      Be Purchased****of
                      Shares**
                  
                  **Average
                      Price**
                  
                  **Announced
                      Plans**
                  
                  **Under
                      the Plans****Period**
                  
                  **Purchased
                      (a)**
                  
                  **Paid
                      per Share**
                  
                  **or
                      Programs (b)**
                  
                  **or
                      Programs**July
                      1-31,
                      2005
                  
                  
                  219,344
                  
                  $
                  49.40
                  
                  
                  -
                  
                  
                  -August
                      1-31,
                      2005
                  
                  
                  698,858
                  
                  $
                  49.46
                  
                  
                  -
                  
                  
                  -September
                      1-30, 2005
                  
                  
                  489,705
                  
                  $
                  51.69
                  
                  
                  -
                  
                  
                  -Third
                      quarter
                      2005
                  
                  
                  1,407,907
                  
                  $
                  50.23
                  
                  
                  -
                  
                  
                  -
 
  (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.
 
 (b)
                    FirstEnergy
                        does not currently have any publicly announced plan or program
                        for share
                        purchases.
  ITEM
                5.OTHER
                INFORMATION
 
 On
                November 1, 2005,
                the Restated Partial Requirements Agreement, dated as of January
                1, 2003, as
                amended August 29, 2003 and June 8, 2004 (as so amended, the “Agreement”), among
                FES, Met-Ed, Penelec and Waverly was amended by the parties to provide
                FES the
                right over the next year to terminate the Agreement at any time upon
                60 days
                written notice. Otherwise, the agreement remains automatically extended
                as to
                each operating company for each successive calendar year unless FES
                or such
                operating company elects to cancel the agreement by November 1 of
                the preceding
                year.
 
 Under
                the Agreement,
                Met-Ed and Penelec currently purchase a portion of their PLR requirements
                from
                FES at fixed prices. The remainder of PLR requirements are currently
                sourced
                from existing NUG contracts or other power contracts with non-affiliated
                third
                party suppliers. If the Agreement were terminated, Met-Ed and Penelec
                would need
                to satisfy the applicable portion of their PLR obligations from other
                sources at
                prevailing prices, which are likely to be higher than the current
                price charged
                by FES under the Agreement, and as a result, Met-Ed’s and Penelec’s purchased
                power costs could materially increase.
 
 Met-Ed,
                Penelec and
                FES are all wholly owned subsidiaries of FirstEnergy and Waverly
                is a wholly
                owned subsidiary of Penelec. A copy of the November 1, 2005 amendment
                is filed
                as Exhibit 10.1 to this Quarterly Report on Form 10-Q.
 **ITEM
            6.**  **EXHIBITS**
 
 **(a)**  **Exhibits**
 
 **Exhibit****Number****JCP&L**12
                  Fixed
                      charge
                      ratios31.2
                  Certification
                      of chief financial officer, as adopted pursuant to Rule
                      13a-15(e)/15d-15(e).31.3
                  Certification
                      of chief executive officer, as adopted pursuant to Rule
                      13a-15(e)/15d-15(e).32.2
                  Certification
                      of chief executive officer and chief financial officer, pursuant
                      to 18
                      U.S.C. Section 1350.**Met-Ed**10.1
                  Notice
                    of
                    Termination Tolling Agreement, Restated Partial Requirements
                    Agreement12
                  Fixed
                      charge
                      ratios31.1
                  Certification
                      of chief executive officer, as adopted pursuant to Rule
                      13a-15(e)/15d-15(e).31.2
                  Certification
                      of chief financial officer, as adopted pursuant to Rule
                      13a-15(e)/15d-15(e).32.1
                  Certification
                      of chief executive officer and chief financial officer, pursuant
                      to 18
                      U.S.C. Section 1350.**Penelec**10.1
                  Notice
                    of
                    Termination Tolling Agreement, Restated Partial Requirements
                    Agreement12
                  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-15(e).31.2
                  Certification
                      of chief financial officer, as adopted pursuant to Rule
                      13a-15(e)/15d-15(e).32.1
                  Certification
                      of chief executive officer and chief financial officer, pursuant
                      to 18
                      U.S.C. Section 1350.
 
 168
 
 **FirstEnergy**10.1
                    Notice
                      of
                      Termination Tolling Agreement, Restated Partial Requirements
                      Agreement10.2
                    Agreement
                        by
                        and between FirstEnergy Generation Corp. and Bechtel Power
                        Corporation
                        dated August 26, 2005.*15
                    Letter
                        from
                        independent registered public accounting firm31.1
                    Certification
                        of chief executive officer, as adopted pursuant to Rule
                        13a-15(e)/15d-15(e).31.2
                    Certification
                        of chief financial officer, as adopted pursuant to Rule
                        13a-15(e)/15d-15(e).32.1
                    Certification
                        of chief executive officer and chief financial officer, pursuant
                        to 18
                        U.S.C. Section 1350.**OE**15
                    Letter
                        from
                        independent registered public accounting firm31.1
                    Certification
                        of chief executive officer, as adopted pursuant to Rule
                        13a-15(e)/15d-15(e).31.2
                    Certification
                        of chief financial officer, as adopted pursuant to Rule
                        13a-15(e)/15d-15(e).32.1
                    Certification
                        of chief executive officer and chief financial officer, pursuant
                        to 18
                        U.S.C. Section 1350.**Penn**15
                    Letter
                        from
                        independent registered public accounting firm.31.1
                    Certification
                        of chief executive officer, as adopted pursuant to Rule
                        13a-15(e)/15d-15(e).31.2
                    Certification
                        of chief financial officer, as adopted pursuant to Rule
                        13a-15(e)/15d-15(e).32.1
                    Certification
                        of chief executive officer and chief financial officer, pursuant
                        to 18
                        U.S.C. Section 1350.**CEI**31.1
                    Certification
                        of chief executive officer, as adopted pursuant to Rule
                        13a-15(e)/15d-15(e).31.2
                    Certification
                        of chief financial officer, as adopted pursuant to Rule
                        13a-15(e)/15d-15(e).32.1
                    Certification
                        of chief executive officer and chief financial officer, pursuant
                        to 18
                        U.S.C. Section 1350.**TE**31.1
                    Certification
                        of chief executive officer, as adopted pursuant to Rule
                        13a-15(e)/15d-15(e).31.2
                    Certification
                        of chief financial officer, as adopted pursuant to Rule
                        13a-15(e)/15d-15(e).32.1
                    Certification
                        of chief executive officer and chief financial officer, pursuant
                        to 18
                        U.S.C. Section 1350.
 *
              Confidential
              Treatment has been requested with respect to certain portions of this
              exhibit.
              Omitted portions have been filed separately with the Securities and
              Exchange
              Commission.
 
 Pursuant
              to
              reporting requirements of respective financings, JCP&L, Met-Ed and Penelec
              are required to file fixed charge ratios as an exhibit to this Form
              10-Q.
              FirstEnergy, OE, CEI, TE and Penn do not have similar financing reporting
              requirements and have not filed their 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 their
              respective total assets of FirstEnergy and its subsidiaries on a consolidated
              basis, or respectively, OE, CEI, TE, Penn, JCP&L, Met-Ed or Penelec, but
              hereby agree to furnish to the Commission on request any such
              documents.
 
 169
 
 
 
 **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
            2,
            2005
 
 
 
 
 
 
 **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
 
  170