**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 March 31, 2006**





**OR**





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


**SECURITIES
      EXCHANGE ACT OF 1934**





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





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












Indicate
        by check
        mark whether each of the registrants (1) has filed all reports required to
        be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934
        during the preceding 12 months (or for such shorter period that the
        registrant was required to file such reports), and (2) has been subject to
        such filing requirements for the past 90 days.
 
 Yes (X) No (  )
 
 Indicate
        by check
        mark whether the registrant is a large accelerated filer, an accelerated
        filer,
        or a non-accelerated filer. See definition of "accelerated filer and large
        accelerated filer" in Rule 12b-2 of the Exchange Act.
 
 Large
                  Accelerated Filer(X)
              FirstEnergy
                  Corp.Accelerated
                  Filer(  
                  )
              N/ANon-accelerated
                  Filer(X)
              Ohio
                  Edison
                  Company, 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
        by check
        mark whether the registrant is a shell company (as defined in Rule 12b-2
        of the
        Act).
 
 Yes (
         ) No (X)
 
 Indicate
        the number
        of shares outstanding of each of the issuer's classes of common stock, as
        of the
        latest practicable date:
 
 **OUTSTANDING****CLASS**
              **AS
                  OF
                  MAY 8, 2006**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 or to recover increased transmission costs, maintenance costs being
          higher than anticipated, legislative and regulatory changes (including
          revised
          environmental requirements), and the legal and regulatory changes resulting
          from
          the implementation of the Energy Policy Act of 2005 (including, but not
          limited
          to, the repeal of the Public Utility Holding Company Act of 1935), the
          uncertainty of the timing and amounts of the capital expenditures (including
          that such amounts could be higher than anticipated) or levels of emission
          reductions related to the Consent Decree resolving the New Source Review
          litigation, adverse regulatory or legal decisions and outcomes (including,
          but
          not limited to, the revocation of necessary licenses or operating permits,
          fines
          or other enforcement actions and remedies) of governmental investigations
          and
          oversight, including by the Securities and Exchange Commission, the United
          States Attorney’s Office, the Nuclear Regulatory Commission and the various
          state public utility commissions as disclosed in the registrants' Securities
          and
          Exchange Commission filings, generally, and with respect to the Davis-Besse
          Nuclear Power Station outage and heightened scrutiny at the Perry Nuclear
          Power
          Plant in particular, the timing and outcome of various proceedings before
          the
          Public Utilities Commission of Ohio and the Pennsylvania Public Utility
          Commission, including the transition rate plan filings for Met-Ed and Penelec,
          the continuing availability and operation of generating units, the ability
          of
          generating units to continue to operate at, or near
          full capacity,
          the inability to accomplish or realize anticipated benefits from strategic
          goals
          (including employee workforce initiatives), the anticipated benefits from
          voluntary pension plan contributions, the ability to improve electric commodity
          margins and to experience growth in the distribution business, the ability
          to
          access the public securities and other capital markets and the cost of
          such
          capital, the outcome, cost and other effects of present and potential legal
          and
          administrative proceedings and claims related to the August 14, 2003
          regional power outage, circumstances which may lead management to seek,
          or the
          Board of Directors to grant, in each case in its sole discretion, authority
          for
          the implementation of a share repurchase program in the future, the risks
          and
          other factors discussed from time to time in the registrants' Securities
          and
          Exchange Commission filings, including their annual report on Form 10-K
          for the
          year ended December 31, 2005, and other similar factors. Dividends declared
          from time to time during any annual period may in aggregate vary from the
          indicated amounts due to circumstances considered by the Board at the time
          of
          the actual declarations. Also, a security rating should not be viewed as
          a
          recommendation to buy, sell, or hold securities and it may be subject to
          revision or withdrawal at any time. The registrants expressly disclaim
          any
          current intention to update any forward-looking statements contained herein
          as a
          result of new information, future events, or otherwise.
   
   **TABLE
        OF
        CONTENTS**
  
 **Pages****Glossary
                  of Terms**
              iii-v**Part
                  I.****Financial
                  Information****Items
                  1. and 2. - Financial Statements and Management’s Discussion and Analysis
                  of****Results
                  of Operation and Financial Condition**Notes
                  to
                  Consolidated Financial Statements
              1-23**FirstEnergy
                  Corp.**Consolidated
                  Statements of Income
              24Consolidated
                  Statements of Comprehensive Income
              25Consolidated
                  Balance Sheets
              26Consolidated
                  Statements of Cash Flows
              27Report
                  of
                  Independent Registered Public Accounting Firm
              28Management's
                  Discussion and Analysis of Results of Operations and
              29-58Financial
                  Condition**Ohio
                  Edison Company**Consolidated
                  Statements of Income and Comprehensive Income
              59Consolidated
                  Balance Sheets
              60Consolidated
                  Statements of Cash Flows
              61Report
                  of
                  Independent Registered Public Accounting Firm
              62Management's
                  Discussion and Analysis of Results of Operations and
              63-74Financial
                  Condition**The
                  Cleveland Electric Illuminating Company**Consolidated
                  Statements of Income and Comprehensive Income
              75Consolidated
                  Balance Sheets
              76Consolidated
                  Statements of Cash Flows
              77Report
                  of
                  Independent Registered Public Accounting Firm
              78Management's
                  Discussion and Analysis of Results of Operations and
              79-89Financial
                  Condition**The
                  Toledo Edison Company**Consolidated
                  Statements of Income and Comprehensive Income
              90Consolidated
                  Balance Sheets
              91Consolidated
                  Statements of Cash Flows
              92Report
                  of
                  Independent Registered Public Accounting Firm
              93Management's
                  Discussion and Analysis of Results of Operations and
              94-104Financial
                  Condition**Pennsylvania
                  Power Company**ConsolidatedStatements of
                  Income and Comprehensive Income
              105ConsolidatedBalance
                  Sheets
              106ConsolidatedStatements of
                  Cash Flows
              107Report
                  of
                  Independent Registered Public Accounting Firm
              108Management's
                  Discussion and Analysis of Results of Operations and
              109-115Financial
                  Condition
 
 
  i
  **TABLE
        OF
        CONTENTS (Cont'd)**
 
 
 **Pages****Jersey
                  Central Power & Light Company**Consolidated
                  Statements of Income and Comprehensive Income
              116Consolidated
                  Balance Sheets
              117Consolidated
                  Statements of Cash Flows
              118Report
                  of
                  Independent Registered Public Accounting Firm
              119Management's
                  Discussion and Analysis of Results of Operations and
              120-128Financial
                  Condition**Metropolitan
                  Edison Company**Consolidated
                  Statements of Income and Comprehensive Income
              129Consolidated
                  Balance Sheets
              130Consolidated
                  Statements of Cash Flows
              131Report
                  of
                  Independent Registered Public Accounting Firm
              132Management's
                  Discussion and Analysis of Results of Operations and
              133-141Financial
                  Condition**Pennsylvania
                  Electric Company**Consolidated
                  Statements of Income and Comprehensive Income
              142Consolidated
                  Balance Sheets
              143Consolidated
                  Statements of Cash Flows
              144Report
                  of
                  Independent Registered Public Accounting Firm
              145Management's
                  Discussion and Analysis of Results of Operations and
              146-154Financial
                  Condition**Item
                  3.****Quantitative
                  and Qualitative Disclosures About Market Risk**
              155**Item
                  4.****Controls
                  and Procedures**
              155**Part
                  II.****Other
                  Information****Item
                  1.****Legal
                  Proceedings**
              156**Item
                  1A.****Risk
                  Factors**
              156**Item
                  2.****Unregistered
                  Sales of Equity Securities and Use of Proceeds**
              156**Item
                  6.****Exhibits**
              156
   ii
   **GLOSSARY
        OF
        TERMS**
 
 The
        following
        abbreviations and acronyms are used in this report to identify FirstEnergy
        Corp.
        and its current and former subsidiaries:
 
 ATSI
              American
                  Transmission Systems, Inc., owns and operates transmission
                  facilitiesCEI
              The
                  Cleveland
                  Electric Illuminating Company, an Ohio electric utility operating
                  subsidiaryCenterior
              Centerior
                  Energy Corporation, former parent of CEI and TE, which merged with
                  OE to
                  form FirstEnergy on November 8, 1997.CFC
              Centerior
                  Funding Corporation, a wholly owned finance subsidiary of
                  CEICompanies
              OE,
                  CEI, TE,
                  Penn, JCP&L, Met-Ed and PenelecFENOC
              FirstEnergy
                  Nuclear Operating Company, operates nuclear generating
                  facilitiesFES
              FirstEnergy
                  Solutions Corp., provides energy-related products and
                  servicesFESC
              FirstEnergy
                  Service Company, provides legal, financial, and other corporate
                  support
                  servicesFGCO
              FirstEnergy
                  Generation Corp., owns and operates non-nuclear generating
                  facilitiesFirstCom
              First
                  Communications, LLC, provides local and long-distance telephone
                  serviceFirstEnergy
              FirstEnergy
                  Corp., a public utility holding companyFSG
              FirstEnergy
                  Facilities Services Group, LLC, the parent company of several heating,
                  ventilation,
                air
                  conditioning and energy management companiesGPU
              GPU,
                  Inc.,
                  former parent of JCP&L, Met-Ed and Penelec, which merged with
                  FirstEnergy on
                November 7,
                  2001JCP&L
              Jersey
                  Central
                  Power & Light Company, a New Jersey electric utility operating
                  subsidiaryJCP&L
                  Transition
              JCP&L
                  Transition Funding LLC, a Delaware limited liability company and
                  issuer of
                  transition bondsMet-Ed
              Metropolitan
                  Edison Company, a Pennsylvania electric utility operating
                  subsidiaryMYR
              MYR
                  Group,
                  Inc., a utility infrastructure construction service
                  companyNGC
              FirstEnergy
                  Nuclear Generation Corp., owns nuclear generating
                  facilitiesOE
              Ohio
                  Edison
                  Company, an Ohio electric utility operating subsidiaryOE
                  Companies
              OE
                  and
                  PennOhio
                  Companies
              CEI,
                  OE and
                  TEPenelec
              Pennsylvania
                  Electric Company, a Pennsylvania electric utility operating
                  subsidiaryPenn
              Pennsylvania
                  Power Company, a Pennsylvania electric utility operating subsidiary
                  of
                  OEPNBV
              PNBV
                  Capital
                  Trust, a special purpose entity created by OE in 1996Shippingport
              Shippingport
                  Capital Trust, a special purpose entity created by CEI and TE in
                  1997TE
              The
                  Toledo
                  Edison Company, an Ohio electric utility operating
                  subsidiaryTEBSA
              Termobarranquilla
                  S.A., Empresa de Servicios PublicosThe
                  following
                  abbreviations and acronyms are used to identify frequently used
                  terms in
                  this report:ALJ
              Administrative
                  Law JudgeAOCL
              Accumulated
                  Other Comprehensive LossAPB
              Accounting
                  Principles BoardAPB
                  25
              APB
                  Opinion
                  25, "Accounting for Stock Issued to Employees"APB
                  29
              APB
                  Opinion
                  No. 29, "Accounting for Nonmonetary Transactions"ARB
              Accounting
                  Research BulletinARB
                  43
              ARB
                  No. 43,
                  "Restatement and Revision of Accounting Research
                  Bulletins"ARO
              Asset
                  Retirement ObligationBGS
              Basic
                  Generation ServiceCAIDI
              Customer
                  Average Interruption Duration IndexCAIR
              Clean
                  Air
                  Interstate RuleCAL
              Confirmatory
                  Action LetterCAMR
              Clean
                  Air
                  Mercury RuleCBP
              Competitive
                  Bid ProcessCO2
              Carbon
                  DioxideCTC
              Competitive
                  Transition ChargeDOJ
              United
                  States
                  Department of JusticeDRA
              Division
                  of
                  the Ratepayer AdvocateECAR
              East
                  Central
                  Area Reliability Coordination AgreementEITF
              Emerging
                  Issues Task ForceEITF
                  04-13
              EITF
                  Issue No.
                  04-13, “Accounting for Purchases and Sales of Inventory with the Same
                  Counterparty"EPA
              Environmental
                  Protection AgencyEPACT
              Energy
                  Policy
                  Act of 2005
 
 iii
 **GLOSSARY
            OF TERMS Cont'd.**
  ERO
                Electric
                    Reliability OrganizationFASB
                Financial
                    Accounting Standards BoardFERC
                Federal
                    Energy
                    Regulatory CommissionFIN
                FASB
                    InterpretationFIN
                    46R
                FIN
                    46
                    (revised December 2003), "Consolidation of Variable Interest
                    Entities"FIN
                    47
                FIN
                    47,
                    "Accounting for Conditional Asset Retirement Obligations - an
                    interpretation of FASB Statement No. 143"FMB
                First
                    Mortgage
                    BondsGAAP
                Accounting
                    Principles Generally Accepted in the United StatesGCAF
                Generation
                    Charge Adjustment FactorGHG
                Greenhouse
                    GasesKWH
                Kilowatt-hoursLOC
                Letter
                    of
                    CreditMEIUG
                Met-Ed
                    Industrial Users GroupMISO
                Midwest
                    Independent Transmission System Operator, Inc.Moody’s
                Moody’s
                    Investors ServiceMOU
                Memorandum
                    of
                    UnderstandingMTC
                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
                    GenerationNUGC
                Non-Utility
                    Generation ChargeOCA
                Office
                    of
                    Consumer AdvocateOCC
                Office
                    of the
                    Ohio Consumers' CounselOCI
                Other
                    Comprehensive IncomeOPEB
                Other
                    Post-Employment BenefitsOSBA
                Office
                    of
                    Small Business AdvocateOTS
                Office
                    of
                    Trial StaffPCAOB
                Public
                    Company
                    Accounting Oversight BoardPICA
                Penelec
                    Industrial Customer AssociationPJM
                PJM
                    Interconnection L. L. C.PLR
                Provider
                    of
                    Last ResortPPUC
                Pennsylvania
                    Public Utility CommissionPRP
                Potentially
                    Responsible PartyPUCO
                Public
                    Utilities Commission of OhioPUHCA
                Public
                    Utility
                    Holding Company Act of 1935RCP
                Rate
                    Certainty
                    PlanRFP
                Request
                    for
                    ProposalRSP
                Rate
                    Stabilization PlanRTC
                Regulatory
                    Transition ChargeRTO
                Regional
                    Transmission OrganizationS&P
                Standard
&
                    Poor’s Ratings ServiceSAIFI
                System
                    Average
                    Interruption Frequency IndexSBC
                Societal
                    Benefits ChargeSEC
                U.S.
                    Securities and Exchange CommissionSFAS
                Statement
                    of
                    Financial Accounting StandardsSFAS
                    123
                SFAS
                    No. 123,
                    "Accounting for Stock-Based Compensation"SFAS
                    123(R)
                SFAS
                    No.
                    123(R), "Share-Based Payment"SFAS
                    133
                SFAS
                    No. 133,
                    “Accounting for Derivative Instruments and Hedging
                    Activities”SFAS
                    140
                SFAS
                    No. 140,
                    “Accounting for Transfers and Servicing of Financial Assets and
                  Extinguishment
                    of Liabilities”SFAS
                    143
                SFAS
                    No. 143,
                    "Accounting for Asset Retirement Obligations"SFAS
                    144
                SFAS
                    No. 144,
                    "Accounting for the Impairment or Disposal of Long-Lived
                    Assets"SFAS
                    155
                SFAS
                    No. 155,
                    "Accounting for Certain Hybrid Financial Instruments - an amendment
                    of
                    FASBStatements
                    No.
                    133 and 140"SO2
                Sulfur
                    DioxideTBC
                Transition
                    Bond Charge
 
 iv
 **GLOSSARY
            OF TERMS Cont'd.**
  TMI-1
                Three
                    Mile
                    Island Unit 1TMI-2
                Three
                    Mile
                    Island Unit 2VIE
                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, NGC, FESC and FSG.
 
 FirstEnergy and its subsidiaries follow GAAP and comply with the regulations,
        orders, policies and practices prescribed by the SEC, FERC and, as applicable,
        PUCO, PPUC and NJBPU. The preparation of financial statements in conformity
        with
        GAAP requires management to make periodic estimates and assumptions that
        affect
        the reported amounts of assets, liabilities, revenues and expenses and
        disclosure of contingent assets and liabilities. Actual results could differ
        from these estimates. The reported results of operations are not indicative
        of
        results of operations for any future period.
 
 These statements should be read in conjunction with the financial statements
        and
        notes included in the combined Annual Report on Form 10-K for the year ended
        December 31, 2005 for FirstEnergy and the Companies. The consolidated
        unaudited financial statements of FirstEnergy and each of the Companies reflect
        all normal recurring adjustments that, in the opinion of management, are
        necessary to fairly present results of operations for the interim periods.
        Certain businesses divested in the first and second quarters of 2005 have
        been
        classified as discontinued operations on the Consolidated Statements of Income
        (see Note 4). As discussed in Note 13, interim period segment reporting in
        2005
        was reclassified to conform with the current year business segment organizations
        and operations.
 
 FirstEnergy and its subsidiaries consolidate all majority-owned subsidiaries
        over which they exercise control and, when applicable, entities for which
        they
        have a controlling financial interest. Intercompany transactions and balances
        are eliminated in consolidation. FirstEnergy consolidates a VIE (see Note
        9)
        when it is determined to be the VIE's primary beneficiary. Investments in
        nonconsolidated affiliates over which FirstEnergy and its subsidiaries have
        the
        ability to exercise significant influence, but not control, (20-50 percent
        owned
        companies, joint ventures and partnerships) are accounted for under the equity
        method. Under the equity method, the interest in the entity is reported as
        an
        investment in the Consolidated Balance Sheet and the percentage share of
        the
        entity’s earnings is reported in the Consolidated Statement of Income. Certain
        prior year amounts have been reclassified to conform to the current
        presentation.
 
 FirstEnergy's and the Companies' independent registered public accounting
        firm
        has performed reviews of, and issued reports on, these consolidated interim
        financial statements in accordance with standards established by the PCAOB.
        Pursuant to Rule 436(c) under the Securities Act of 1933, their reports of
        those
        reviews should not be considered a report within the meaning of Section 7
        and 11
        of that Act, and the independent registered public accounting firm’s liability
        under Section 11 does not extend to them.
  1
  **2.
        -
        EARNINGS PER SHARE**
 
 Basic earnings per share are computed using the weighted average of actual
        common shares outstanding during the respective period as the denominator.
        The
        denominator for diluted earnings per share reflects the weighted average
        of
        common shares outstanding plus the potential additional common shares that
        could
        result if dilutive securities and other agreements to issue common stock
        were
        exercised. Stock-based awards to purchase 0.5 million shares of common
        stock in the three months ended March 31, 2005 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 March 31, 2006. The following table reconciles the
        denominators for basic and diluted earnings per share from Income Before
        Discontinued Operations:
 
 **Three
                  Months Ended****Reconciliation
                  of Basic and Diluted**
              
              **March
                  31,****Earnings
                  per Share**
              
              **2006**
              
              **2005*****(In
                  millions)***Income
                  Before
                  Discontinued Operations
              
              $
              221
              
              $
              141Average
                  Shares
                  of Common Stock Outstanding:Denominator
                  for basic earnings per share(weighted
                  average shares outstanding)
              
              
              329
              
              
              328Assumed
                  exercise of dilutive stock options and awards
              
              
              1
              
              
              1Denominator
                  for diluted earnings per share
              
              
              330
              
              
              329Income
                  Before
                  Discontinued Operations per common share:Basic
              
              $
              0.67
              
              $
              0.43Diluted
              
              $
              0.67
              
              $
              0.42
 
 **3.
        -
        GOODWILL**
 
 FirstEnergy's goodwill primarily relates to its regulated services segment.
        In
        the three months ended March 31, 2006, FirstEnergy adjusted goodwill
        related to the divestiture of a non-core asset (60% interest in MYR), a
        successful tax claim relating to the former Centerior companies, and an
        adjustment to the former GPU companies due to the realization of a tax benefit
        that had been reserved in purchase accounting.
 
 A summary of the changes in goodwill for the three months ended March 31,
        2006
        is shown below:
 
 **FirstEnergy**
              
              **CEI**
              
              **TE**
              
              **JCP&L**
              
              **Met-Ed**
              
              **Penelec*****(In
                  millions)***Balance
                  as of
                  January 1, 2006
              
              $
              6,010
              
              $
              1,689
              
              $
              501
              
              $
              1,986
              
              $
              864
              
              $
              882Non-core
                  assets sale
              
              
              (53
              )Adjustments
                  related to Centerior acquisition
              
              
              (1
              )
              
              (1
              )Adjustments
                  related to GPU acquisition
              
              
              (16
              )
              
              
              
              
              
              
              
              (8
              )
              
              (4
              )
              
              (4
              )Balance
                  as of
                  March 31, 2006
              
              $
              5,940
              
              $
              1,688
              
              $
              501
              
              $
              1,978
              
              $
              860
              
              $
              878
 
 **4.
        -
        DIVESTITURES AND DISCONTINUED OPERATIONS**
 
 In March 2006, FirstEnergy sold 60% of its interest in MYR for an after-tax
        gain
        of $0.2 million. As a result, FirstEnergy deconsolidated MYR and began
        accounting for its remaining 40% interest under the equity method.
  In March 2005, FES sold its retail natural gas business for an after-tax
        gain of
        $5 million and FirstEnergy sold 51% of its interest in FirstCom for an
        after-tax gain of $4 million. FirstEnergy accounts for its remaining 31.85%
        interest in FirstCom under the equity method.
 
 FirstEnergy sold two FSG subsidiaries (Elliott-Lewis and Spectrum) and an
        MYR
        subsidiary (Power Piping Company) in the first quarter of 2005, resulting
        in
        aggregate after-tax gains of $12 million. The remaining FSG subsidiaries
        continue to be actively marketed and qualify as assets held for sale in
        accordance with SFAS 144. Management anticipates that the transfer of FSG
        assets, with a net carrying value of $49 million as of March 31, 2006,
        will qualify for recognition as completed sales within one year. As of
        March 31, 2006, the FSG subsidiaries classified as held for sale did not
        meet the criteria for discontinued operations. The carrying amounts of FSG's
        assets and liabilities held for sale are not material and have not been
        classified as assets held for sale on FirstEnergy's Consolidated Balance
        Sheets.
        See Note 13 for FSG's segment financial information.
  2
  Net income (including the gain on sales discussed above) for Elliott-Lewis,
        Power Piping, FES' natural gas business and Cranston (sold in the second
        quarter
        of 2005) of $19 million for the first quarter of 2005 is reported as
        discontinued operations on FirstEnergy's Consolidated Statements of Income.
        Pre-tax operating results for these entities were $4 million for the first
        quarter of 2005. Revenues associated with discontinued operations for the
        first
        quarter of 2005 were $195 million. The following table summarizes the sources
        of
        income from discontinued operation for the three months ended March 31,
        2005:
 
 ***(In
                  millions)***Discontinued
                  Operations (Net of tax)Gain
                  on
                  sale:Natural
                  gas
                  business
              
              $
              5FSG
                  subsidiaries and Power Piping
              
              
              12Reclassification
                  of operating income
              
              
              2Total
              
              $
              19
 
 **5.
        -
        DERIVATIVE INSTRUMENTS**
 
 FirstEnergy is exposed to financial risks resulting from the fluctuation
        of
        interest rates and commodity prices, including prices for electricity, natural
        gas, coal and energy transmission. To manage the volatility relating to these
        exposures, FirstEnergy uses a variety of non-derivative and derivative
        instruments, including forward contracts, options, futures contracts and
        swaps.
        The derivatives are used principally for hedging purposes. FirstEnergy’s Risk
        Policy Committee, comprised of members of senior management, provides general
        management oversight to risk management activities throughout the Company.
        They
        are responsible for promoting the effective design and implementation of
        sound
        risk management programs. They also oversee compliance with corporate risk
        management policies and established risk management practices.
 
 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 criterion are accounted for on the accrual
        basis. The changes in the fair value of derivative instruments that do not
        meet
        the normal purchase and sales criteria are recorded in current earnings,
        in
        AOCL, or as part of the value of the hedged item, depending on whether or
        not it
        is designated as part of a hedge transaction, the nature of the hedge
        transaction and hedge effectiveness.
 
 FirstEnergy hedges anticipated transactions using cash flow hedges. Such
        transactions include hedges of anticipated electricity and natural gas purchases
        and anticipated interest payments associated with future debt issues. The
        effective portion of such hedges are initially recorded in equity as other
        comprehensive income or loss and are subsequently included in net income
        as the
        underlying hedged commodities are delivered or interest payments are made.
        Gains
        and losses from any ineffective portion of cash flow hedges are included
        directly in earnings.
 
 The net deferred losses of $53 million included in AOCL as of March 31, 2006,
        for derivative hedging activity, as compared to the December 31, 2005
        balance of $78 million of net deferred losses, resulted from a $19 million
        decrease related to current hedging activity and a $6 million decrease due
        to
        net hedge losses included in earnings during the three months ended March
        31,
        2006. Approximately $11 million (after tax) of the net deferred losses on
        derivative instruments in AOCL as of March 31, 2006 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 has entered into swaps that have been designated as fair value
        hedges of fixed-rate, long-term debt issues to protect against the risk of
        changes in the fair value of fixed-rate debt instruments due to lower interest
        rates. Swap maturities, call options, fixed interest rates received, and
        interest payment dates match those of the underlying debt obligations. During
        the first quarter of 2006, FirstEnergy unwound swaps with a total notional
        amount of $350 million for which it paid $1 million in cash. The
        losses will be recognized in earnings over the remaining maturity of each
        respective hedged security as increased interest expense. As of March 31,
        2006, the aggregate notional value of interest rate swap agreements outstanding
        was $750 million.
 
 During 2005 and the first quarter of 2006, FirstEnergy entered into several
        forward starting swap agreements (forward swaps) in order to hedge a portion
        of
        the consolidated interest rate risk associated with the anticipated issuances
        of
        fixed-rate, long-term debt securities for one or more of its consolidated
        entities during 2006 - 2008 as outstanding debt matures. These derivatives
        are
        treated as cash flow hedges, protecting against the risk of changes in future
        interest payments resulting from changes in benchmark U.S. Treasury rates
        between the date of hedge inception and the date of the debt issuance. During
        the first quarter of 2006, FirstEnergy revised its financing plan related
        to
        forward swaps with an aggregate notional amount of $500 million, impacting
        the
        term and timing of the respective issuances. As required by SFAS 133,
        FirstEnergy de-designated the forward swaps and assessed the amount of
        ineffectiveness. FirstEnergy terminated the forward swaps and received cash
        of
        $16 million, of which approximately $5 million ($3 million net of tax) was
        deemed ineffective and recognized in earnings in the first quarter of 2006.
        The
        remaining gain deemed effective in the amount of approximately $11 million
        ($7
        million net of tax) was recorded in other comprehensive income and will
        subsequently be recognized in earnings over the terms of the respective forward
        swaps. As of March 31, 2006, FirstEnergy had forward swaps with an
        aggregate notional amount of $1 billion and a fair value of
        $25 million.
   3
  **6.
        - STOCK
        BASED COMPENSATION**
  FirstEnergy has the following stock-based compensation programs: Long-term
        Incentive Program (LTIP); Executive Deferred Compensation Plan (EDCP); Employee
        Stock Ownership Plan (ESOP) and Deferred Compensation Plan for Outside Directors
        (DCPD), which were previously accounted for under the recognition and
        measurement principles of APB 25 and related interpretations. The LTIP includes
        four stock-based compensation programs - restricted stock, restricted stock
        units, stock options, and performance shares.
 
 Effective January 1, 2006, FirstEnergy adopted SFAS 123(R), which requires
        the
        expensing of stock-based compensation. Under SFAS 123(R), all share-based
        compensation cost is measured at the grant date, based on the fair value
        of the
        award and is recognized as an expense over the employee’s requisite service
        period. FirstEnergy adopted the modified prospective method, under which
        compensation expense recognized in the first quarter of 2006 includes the
        expense for all share-based payments granted prior to but not yet vested
        as of
        January 1, 2006. Results for prior periods have not been restated.
 
 Under APB 25, no compensation expense was reflected in net income for
        stock options as all options granted under those plans have exercise prices
        equal to the market value of the underlying common stock on the respective
        grant
        dates, resulting in substantially no intrinsic value. The pro-forma effects
        on
        net income for stock options were instead disclosed in a footnote to the
        financial statements. Under APB 25 and SFAS 123(R) expense was recorded in
        the
        income statement for restricted stock, restricted stock units, performance
        shares and the EDCP and DCPD programs. No stock options have been issued
        subsequent to the third quarter of 2004. Consequently, the impact of adopting
        SFAS 123(R) was not material to FirstEnergy's net income and earnings per
        share
        in the first quarter 2006. In the year of adoption all disclosures prescribed
        by
        SFAS 123(R) are required to be included in both the quarterly Form 10-Q filings
        as well as the annual Form 10-K filing. However, due to the immaterial impact
        of
        the adoption of SFAS 123(R) on FirstEnergy's financial results, only condensed
        disclosure has been provided. For annual disclosures see FirstEnergy's 2005
        Form
        10-K.
 
 The following table illustrates the effect on net income and earnings per
        share
        for the first quarter of 2005, as if FirstEnergy had adopted SFAS 123(R)
        as of
        January 1, 2005 (in millions):
 
 **March
                  31,****2005**Net
                  Income, as
                  reported
              
              $
              160Add
                  back
                  compensation expensereported
                  in
                  net income, net of tax (based on
              
              
              8APB
                  25)*Deduct
                  compensation expense basedupon
                  estimated
                  fair value, net of tax*
              
              
              (11
              )Pro
                  forma net
                  income
              
              $
              157Earnings
                  Per
                  Share of Common Stock -BasicAs
                  Reported
              
              $
              0.49Pro
                  Forma
              
              $
              0.48DilutedAs
                  Reported
              
              $
              0.48Pro
                  Forma
              
              $
              0.48
 
 *  Includes
        restricted
        stock, restricted stock units, stock options, performance
 shares,
        ESOP, EDCP
        and DCPD.
 
 **7.
        - ASSET
        RETIREMENT OBLIGATIONS**
  FirstEnergy has recognized applicable legal obligations under SFAS 143 for
        nuclear power plant decommissioning, reclamation of a sludge disposal pond
        and
        closure of two coal ash disposal sites. In addition, FirstEnergy has recognized
        conditional retirement obligations (primarily for asbestos remediation) in
        accordance with FIN 47, which was implemented on December 31, 2005. Had FIN
        47 been applied in the first quarter of 2005, the impact on earnings would
        have
        been immaterial.
  4
 
 The ARO liability of $1.1 billion as of March 31, 2006 primarily related
        to the
        nuclear decommissioning of the Beaver Valley, Davis-Besse, Perry and TMI-2
        nuclear generating facilities. The obligation to decommission these units
        was
        developed based on site specific studies performed by an independent engineer.
        FirstEnergy utilized an expected cash flow approach to measure the fair value
        of
        the nuclear decommissioning ARO.
 
 FirstEnergy maintains nuclear decommissioning trust funds that are legally
        restricted for purposes of settling the nuclear decommissioning ARO. As of
        March 31, 2006, the fair value of the decommissioning trust assets was
        $1.8 billion.
 
 The following tables analyze changes to the ARO balance during the first
        quarters of 2006 and 2005, respectively.
 
 **ARO
                  Reconciliation**
              
              **FirstEnergy**
              
              **OE**
              
              **CEI**
              
              **TE**
              
              **Penn**
              
              **JCP&L**
              
              **Met-Ed**
              
              **Penelec*****(In
                  millions)***Balance,
                  January 1, 2006
              
              $
              1,126
              
              $
              83
              
              $
              8
              
              $
              25
              
              $
              -
              
              $
              80
              
              $
              142
              
              $
              72Liabilities
                  incurred
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Liabilities
                  settled
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Accretion
              
              
              18
              
              
              1
              
              
              -
              
              
              -
              
              
              -
              
              
              1
              
              
              2
              
              
              1Revisions
                  in
                  estimated cash flows
              
              
              4
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Balance,
                  March
                  31, 2006
              
              $
              1,148
              
              $
              84
              
              $
              8
              
              $
              25
              
              $
              -
              
              $
              81
              
              $
              144
              
              $
              73Balance,
                  January 1, 2005
              
              $
              1,078
              
              $
              201
              
              $
              272
              
              $
              194
              
              $
              138
              
              $
              73
              
              $
              133
              
              $
              66Liabilities
                  incurred
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Liabilities
                  settled
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Accretion
              
              
              17
              
              
              3
              
              
              4
              
              
              3
              
              
              2
              
              
              2
              
              
              2
              
              
              1Revisions
                  in
                  estimated cash flows
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Balance,
                  March
                  31, 2005
              
              $
              1,095
              
              $
              204
              
              $
              276
              
              $
              197
              
              $
              140
              
              $
              75
              
              $
              135
              
              $
              67
 
 **8.
        - PENSION
        AND OTHER POSTRETIREMENT BENEFITS:**
 
 FirstEnergy provides noncontributory defined benefit pension plans that cover
        substantially all of its employees. The trusteed plans provide defined benefits
        based on years of service and compensation levels. FirstEnergy also provides
        a
        minimum amount of noncontributory life insurance to retired employees in
        addition to optional contributory insurance. Health care benefits, which
        include
        certain employee contributions, deductibles and co-payments, are available
        upon
        retirement to employees hired prior to January 1, 2005, their dependents
        and, under certain circumstances, their survivors. FirstEnergy recognizes
        the
        expected cost of providing other postretirement benefits to employees, their
        beneficiaries and covered dependents from the time employees are hired until
        they become eligible to receive those benefits.
 
 The components of FirstEnergy's net periodic pension cost and other
        postretirement benefit cost (including amounts capitalized) for the three
        months
        ended March 31, 2006 and 2005, consisted of the following:
 
 **Other
                  Postretirement****Pension
                  Benefits**
              
              **Benefits****2006**
              
              **2005**
              
              **2006**
              
              **2005*****(In
                  millions)***Service
                  cost
              
              $
              21
              
              $
              19
              
              $
              9
              
              $
              10Interest
                  cost
              
              
              66
              
              
              64
              
              
              26
              
              
              28Expected
                  return on plan assets
              
              
              (99
              )
              
              (86
              )
              
              (12
              )
              
              (11
              )Amortization
                  of prior service cost
              
              
              2
              
              
              2
              
              
              (19
              )
              
              (11
              )Recognized
                  net
                  actuarial loss
              
              
              15
              
              
              9
              
              
              14
              
              
              10Net
                  periodic
                  cost
              
              $
              5
              
              $
              8
              
              $
              18
              
              $
              26
 
  5
  Pension and postretirement benefit obligations are allocated to FirstEnergy’s
        subsidiaries employing the plan participants. The Companies capitalize employee
        benefits related to construction projects. The net periodic pension costs
        (credits) and net periodic postretirement benefit costs (including amounts
        capitalized) recognized by each of the Companies for the three months ended
        March 31, 2006 and 2005 were as follows:
 
 **Pension
                  Benefit Cost (Credit)**
              
              **Other
                  Postretirement**
                **Benefit
                  Cost****2006**
              
              **2005**
              
              **2006**
              
              **2005*****(In
                  millions)***OE
              
              $
              (1.1
              )
              $
              0.2
              
              $
              3.4
              
              $
              5.8Penn
              
              
              (0.4
              )
              
              (0.2
              )
              
              0.8
              
              
              1.2CEI
              
              
              1.0
              
              
              0.3
              
              
              2.8
              
              
              3.8TE
              
              
              0.2
              
              
              0.3
              
              
              2.0
              
              
              2.2JCP&L
              
              
              (1.4
              )
              
              (0.2
              )
              
              0.6
              
              
              2.7Met-Ed
              
              
              (1.7
              )
              
              (1.1
              )
              
              0.7
              
              
              0.4Penelec
              
              
              (1.3
              )
              
              (1.3
              )
              
              1.8
              
              
              1.9Other
                  FirstEnergy
                subsidiaries
              
              
              9.9
              
              
              9.5
              
              
              6.1
              
              
              8.1$
              5.2
              
              $
              7.5
              
              $
              18.2
              
              $
              26.1
 
 **9.
        -
        VARIABLE INTEREST ENTITIES**
 
 FIN 46R addresses the consolidation of VIEs, including special-purpose entities,
        that are not controlled through voting interests or in which the equity
        investors do not bear the entity's residual economic risks and rewards.
        FirstEnergy and its subsidiaries consolidate VIEs when they are determined
        to be
        the VIE's primary beneficiary as defined by FIN 46R.
 
 **Leases**
 
 FirstEnergy’s consolidated financial statements include PNBV and Shippingport,
        VIEs created in 1996 and 1997, respectively, to refinance debt originally
        issued
        in connection with the sale and leaseback transactions. PNBV and Shippingport
        financial data are included in the consolidated financial statements of OE
        and
        CEI, respectively.
 
 PNBV was established to purchase a portion of the lease obligation bonds
        issued
        in connection with OE’s 1987 sale and leaseback of its interests in the Perry
        Plant and Beaver Valley Unit 2. OE used debt and available funds to purchase
        the
        notes issued by PNBV. Ownership of PNBV includes a 3% equity interest by
        an
        unaffiliated third party and a 3% equity interest held by OES Ventures, a
        wholly
        owned subsidiary of OE. Shippingport was established to purchase all of the
        lease obligation bonds issued in connection with CEI’s and TE’s Bruce Mansfield
        Plant sale and leaseback transaction in 1987. CEI and TE used debt and available
        funds to purchase the notes issued by Shippingport.
 
 OE, CEI and TE are exposed to losses under the applicable sale-leaseback
        agreements upon the occurrence of certain contingent events that each company
        considers unlikely to occur. OE, CEI and TE each have a maximum exposure
        to loss
        under these provisions of approximately $1 billion, which represents the
        net amount of casualty value payments upon the occurrence of specified casualty
        events that render the applicable plant worthless. Under the applicable sale
        and
        leaseback agreements, OE, CEI and TE have net minimum discounted lease payments
        of $666 million, $96 million and $535 million, respectively, that
        would not be payable if the casualty value payments are made.
 
 **Power
        Purchase Agreements**
  In
        accordance
        with FIN 46R, FirstEnergy evaluated its power purchase agreements and determined
        that certain NUG entities may be VIEs to the extent they own a plant that
        sells
        substantially all of its output to the Companies and the contract price for
        power is correlated with the plant’s variable costs of production. FirstEnergy,
        through its subsidiaries JCP&L, Met-Ed and Penelec, maintains approximately
        30 long-term power purchase agreements with NUG entities. The agreements
        were
        entered into pursuant to the Public Utility Regulatory Policies Act of 1978.
        FirstEnergy was not involved in the creation of, and has no equity or debt
        invested in, these entities.
 
 FirstEnergy has determined that for all but eight of these entities, neither
        JCP&L, Met-Ed nor Penelec have variable interests in the entities or the
        entities are governmental or not-for-profit organizations not within the
        scope
        of FIN 46R. JCP&L, Met-Ed or Penelec may hold variable interests in the
        remaining eight entities, which sell their output at variable prices that
        correlate to some extent with the operating costs of the plants. As required
        by
        FIN 46R, FirstEnergy periodically requests from these eight entities the
        information necessary to determine whether they are VIEs or whether JCP&L,
        Met-Ed or Penelec is the primary beneficiary. FirstEnergy has been unable
        to
        obtain the requested information, which in most cases was deemed by the
        requested entity to be proprietary. As such, FirstEnergy applied the scope
        exception that exempts enterprises unable to obtain the necessary information
        to
        evaluate entities under FIN 46R.
  6
  Since FirstEnergy has no equity or debt interests in the NUG entities, its
        maximum exposure to loss relates primarily to the above-market costs it incurs
        for power. As of March 31, 2006, the net projected above-market loss
        liability recognized for these eight NUG agreements was $102 million.
        Purchased power costs from these entities during the first quarters of 2006
        and
        2005 are shown in the table below:
 
 **Three
                  Months Ended****March
                  31,****2006**
              
              **2005*****(In
                  millions)***JCP&L
              
              $
              15
              
              $
              21Met-Ed
              
              
              16
              
              
              16Penelec
              
              
              8
              
              
              7$
              39
              
              $
              44
 
 **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 $100,000 that is payable from TBC collections.
 
 **10.
        -
        COMMITMENTS, GUARANTEES AND CONTINGENCIES:**
 
 **(A)**  **GUARANTEES
        AND OTHER ASSURANCES**
 
 As part of normal business activities, FirstEnergy enters into various
        agreements on behalf of its subsidiaries to provide financial or performance
        assurances to third parties. These agreements include contract guarantees,
        surety bonds and LOCs. As of March 31, 2006, outstanding guarantees and
        other assurances totaled approximately $3.3 billion -- contract guarantees
        ($1.8 billion), surety bonds ($0.2 billion) and LOCs
        ($1.3 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. The likelihood is remote
        that
        such parental guarantees of $0.9 billion (included in the $1.8 billion discussed
        above) as of March 31, 2006 would increase amounts otherwise payable by
        FirstEnergy to meet its obligations incurred in connection with financings
        and
        ongoing energy and energy-related activities.
 
 While these types of guarantees are normally parental commitments for the
        future
        payment of subsidiary obligations, subsequent to the occurrence of a credit
        rating-downgrade or “material adverse event” the immediate posting of cash
        collateral or provision of an LOC may be required of the subsidiary. As of
        March 31, 2006, FirstEnergy's maximum exposure under these collateral
        provisions was $456 million.
 
 Most of FirstEnergy's surety bonds are backed by various indemnities common
        within the insurance industry. Surety bonds and related FirstEnergy guarantees
        of $136 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.
  7
  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.
 
 **Borrowing****Subsidiary
                  Company**
              
              **Parent
                  Company**
              
              **Capacity*****(In
                  millions)***OES
                  Capital,
                  Incorporated
              
              
              OE
              
              $
              170Centerior
                  Funding Corp.
              
              
              CEI
              
              
              200Penn
                  Power
                  Funding LLC
              
              
              Penn
              
              
              25Met-Ed
                  Funding
                  LLC
              
              
              Met-Ed
              
              
              80Penelec
                  Funding LLC
              
              
              Penelec
              
              
              75$
              550
 
 FirstEnergy has also guaranteed the obligations of the operators of the TEBSA
        project, up to a maximum of $6 million (subject to escalation) under the
        project's operations and maintenance agreement. In connection with the sale
        of
        TEBSA in January 2004, the purchaser indemnified FirstEnergy against any
        loss
        under this guarantee. FirstEnergy has also provided an LOC ($36 million as
        of
        March 31, 2006), which is renewable and declines yearly based upon the
        senior outstanding debt of TEBSA.
 
 **(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
        to
        the extent that it competes with companies that are not subject to such
        regulations and therefore do not bear the risk of costs associated with
        compliance, or failure to comply, with such regulations. Overall, FirstEnergy
        believes it is in compliance with existing regulations but is unable to predict
        future changes in regulatory policies and what, if any, the effects of such
        changes would be. FirstEnergy estimates additional capital expenditures for
        environmental compliance of approximately $1.8 billion for 2006 through
        2010.
 
 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.
 
 On December 1, 2005, FirstEnergy issued a comprehensive report to shareholders
        regarding air emissions regulations and an assessment of its future risks
        and
        mitigation efforts.
 
 *Clean
        Air Act
        Compliance*
 
 FirstEnergy is required to meet federally approved SO 2 regulations.
        Violations of such regulations can result in shutdown of the generating unit
        involved and/or civil or criminal penalties of up to $32,500 for each day
        the
        unit is in violation. The EPA has an interim enforcement policy for
        SO 2 regulations in Ohio
        that allows for compliance based on a 30-day averaging period. FirstEnergy
        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% 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.
  8
  *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 CAIR covering a total of 28 states (including Michigan, New Jersey, Ohio
        and
        Pennsylvania) and the District of Columbia based on proposed findings that
        air
        emissions from 28 eastern states and the District of Columbia significantly
        contribute to non-attainment of the NAAQS for fine particles and/or the "8-hour"
        ozone NAAQS in other states. CAIR provides each affected state until 2006
        to
        develop implementing regulations to achieve additional reductions of NO X and SO 2 emissions in two
        phases (Phase I in 2009 for NO x ,
        2010 for
        SO 2 and Phase II in
        2015 for both NO X and SO 2 ).
        FirstEnergy's
        Michigan, Ohio and Pennsylvania fossil-fired generation facilities will be
        subject to caps on SO 2 and NO x emissions, whereas
        its New Jersey fossil-fired generation facilities will be subject to only
        a cap
        on NO X emissions.
        According to the EPA, SO 2 emissions will be
        reduced by 45% (from 2003 levels) by 2010 across the states covered by the
        rule,
        with reductions reaching 73% (from 2003 levels) by 2015, capping SO 2 emissions in
        affected states to just 2.5 million tons annually. NO x emissions will be
        reduced by 53% (from 2003 levels) by 2009 across the states covered by the
        rule,
        with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional NO X cap of 1.3 million
        tons annually. The future cost of compliance with these regulations may be
        substantial and will depend on how they are ultimately implemented by the
        states
        in which FirstEnergy operates affected facilities.
 
 *Mercury
        Emissions*
 
 In December 2000, the EPA announced it would proceed with the development
        of
        regulations regarding hazardous air pollutants from electric power plants,
        identifying mercury as the hazardous air pollutant of greatest concern. On
        March 14, 2005, the EPA finalized the CAMR, which provides a cap-and-trade
        program to reduce mercury emissions from coal-fired power plants in two phases.
        Initially, mercury emissions will be capped nationally at 38 tons by 2010
        (as a "co-benefit" from implementation of SO 2 and NO X emission caps under
        the EPA's CAIR program). Phase II of the mercury cap-and-trade program will
        cap
        nationwide mercury emissions from coal-fired power plants at 15 tons per
        year by 2018. However, the final rules give states substantial discretion
        in
        developing rules to implement these programs. In addition, both the CAIR
        and the
        CAMR have been challenged in the United States Court of Appeals for the District
        of Columbia. FirstEnergy's future cost of compliance with these regulations
        may
        be substantial and will depend on how they are ultimately implemented by
        the
        states in which FirstEnergy operates affected facilities.
 
 The model rules for both CAIR and CAMR contemplate an input-based methodology
        to
        allocate allowances to affected facilities. Under this approach, allowances
        would be allocated based on the amount of fuel consumed by the affected sources.
        FirstEnergy would prefer an output-based generation-neutral methodology in
        which
        allowances are allocated based on megawatts of power produced. Since this
        approach is based on output, new and non-emitting generating facilities,
        including renewables and nuclear, would be entitled to their proportionate
        share
        of the allowances. Consequently, FirstEnergy would be disadvantaged if these
        model rules were implemented because its substantial reliance on non-emitting
        (largely nuclear) generation is not recognized under the input-based
        allocation.
 
 *W.
        H. Sammis
        Plant*
 
 In 1999 and 2000, the EPA issued NOV or Compliance Orders to nine utilities
        alleging violations of the Clean Air Act based on operation and maintenance
        of
        44 power plants, including the W. H. Sammis Plant, which was owned at that
        time
        by OE and Penn. In addition, the DOJ filed eight civil complaints against
        various investor-owned utilities, including a complaint against OE and Penn
        in
        the U.S. District Court for the Southern District of Ohio. These cases are
        referred to as New Source Review cases. On March 18, 2005, OE and Penn
        announced that they had reached a settlement with the EPA, the DOJ and three
        states (Connecticut, New Jersey, and New York) that resolved all issues related
        to the W. H. Sammis Plant New Source Review litigation. This settlement
        agreement was approved by the Court on July 11, 2005, and requires
        reductions of NO X and SO 2 emissions at the
        W. H. Sammis Plant and other coal fired plants through the installation of
        pollution control devices and provides for stipulated penalties for failure
        to
        install and operate such pollution controls in accordance with that agreement.
        Consequently, if FirstEnergy fails to install such pollution control devices,
        for any reason, including, but not limited to, the failure of any third-party
        contractor to timely meet its delivery obligations for such devices, FirstEnergy
        could be exposed to penalties under the settlement agreement. Capital
        expenditures necessary to meet those requirements are currently estimated
        to be
        $1.5 billion (the primary portion of which is expected to be spent in the
        2008 to 2011 time period). On 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 paid by OE and Penn of $7.8 million
        and $0.7 million, respectively. OE and Penn also recognized liabilities in
        the first quarter of 2005 of $9.2 million and $0.8 million,
        respectively, for probable future cash contributions toward environmentally
        beneficial projects.
  9
  *Climate
        Change*
 
 In December 1997, delegates to the United Nations' climate summit in Japan
        adopted an agreement, the Kyoto Protocol, to address global warming by reducing
        the amount of man-made GHG emitted by developed countries by 5.2% from 1990
        levels between 2008 and 2012. The United States signed the Kyoto Protocol
        in
        1998 but it failed to receive the two-thirds vote required for ratification
        by
        the United States Senate. However, the Bush administration has committed
        the
        United States to a voluntary climate change strategy to reduce domestic GHG
        intensity - the ratio of emissions to economic output - by 18% through 2012.
        The
        EPACT established a Committee on Climate Change Technology to coordinate
        federal
        climate change activities and promote the development and deployment of GHG
        reducing technologies.
  FirstEnergy cannot currently estimate the financial impact of climate change
        policies, although the potential restrictions on CO 2 emissions could
        require significant capital and other expenditures. The CO 2 emissions per
        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 March 31, 2006, based on estimates of the
        total costs of cleanup, the Companies' proportionate responsibility for such
        costs and the financial ability of other unaffiliated entities to pay. In
        addition, JCP&L has accrued liabilities for environmental remediation of
        former manufactured gas plants in New Jersey; those costs are being recovered
        by
        JCP&L through a non-bypassable SBC. Total
        liabilities of
        approximately $63 million (JCP&L - $47.3 million, CEI - $1.7 million, TE - $0.2 million,
        Met-Ed - $0.05 million
        and other - $13.7 million)
        have been accrued through March 31, 2006.
 
 **(C)**  **OTHER
        LEGAL
        PROCEEDINGS**
 
 *Power
        Outages
        and Related Litigation*
 
 In July 1999, the Mid-Atlantic States experienced a severe heat wave, which
        resulted in power outages throughout the service territories of many electric
        utilities, including JCP&L's territory. In an investigation into the causes
        of the outages and the reliability of the transmission and distribution systems
        of all four of New Jersey’s electric utilities, the NJBPU concluded that there
        was not a prima facie case demonstrating that, overall, JCP&L provided
        unsafe, inadequate or improper service to its customers. Two class action
        lawsuits (subsequently consolidated into a single proceeding) were filed
        in New
        Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU
        companies, seeking compensatory and punitive damages arising from the July
        1999
        service interruptions in the JCP&L territory.
  10
  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. In December, 2005, JCP&L argued its
        motion for summary judgment before the New Jersey Superior Court on its renewed
        motion to decertify the class and on remaining plaintiffs' negligence and
        breach
        of contract claims. These motions remain pending. FirstEnergy is unable to
        predict the outcome of these matters and no liability has been accrued as
        of
        March 31, 2006.
 
 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
        March 31, 2006 for any expenditure 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 these four cases, the carrier seeks reimbursement
        from various FirstEnergy companies (and, in one case, from PJM, MISO and
        American Electric Power Company, Inc. as well) for claims paid to insureds
        for
        damages allegedly arising as a result of the loss of power on August 14,
        2003. The listed insureds in these cases, in many instances, are not customers
        of any FirstEnergy company. The fourth case involves the claim of a non-customer
        seeking reimbursement for losses incurred when its store was burglarized
        on
        August 14, 2003. On
        March 7,
        2006, the PUCO issued a ruling applicable to all pending cases. Among its
        various rulings, the PUCO consolidated all of the pending outage cases for
        hearing; limited the litigation to service-related claims by customers of
        the
        Ohio operating companies; dismissed FirstEnergy Corp. as a defendant; ruled
        that
        the U.S.-Canada Power System Outage Task Force Report was not admissible
        into
        evidence; and gave the plaintiffs additional time to amend their complaints
        to
        otherwise comply with the PUCO’s underlying order. The plaintiffs in
        one case have since filed an amended complaint. The named FirstEnergy companies
        have answered and also have filed a motion to dismiss the action, which is
        pending. Also, most complainants, along with the FirstEnergy companies, filed
        applications for rehearing with the PUCO over various rulings contained in
        the
        March 7, 2006 order. On April 26, 2006, the PUCO granted rehearing to allow
        the
        insurance company claimants, as insurers, to prosecute their claims in their
        name so long as they also identify the underlying insured entities and the
        Ohio
        utilities which provide their service. The PUCO denied all other motions
        for
        rehearing. No estimate of potential liability is available for any of these
        cases. 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.
        Following the PUCO's March 7, 2006 order, that action was voluntarily
        dismissed by the claimants.
 
 11
 
 In addition to the above proceedings, FirstEnergy 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 has been filed.
        FirstEnergy was also named, along with several other entities, in a complaint
        in
        New Jersey State Court. The allegations against FirstEnergy are based, in
        part,
        on an alleged failure to protect the citizens of Jersey City from an electrical
        power outage. No FirstEnergy entity serves any customers in Jersey City.
        A
        responsive pleading has been filed. On April 28, 2006, the Court granted
        FirstEnergy's motion to dismiss. It is uncertain whether the plaintiff will
        appeal. No estimate of potential liability has been undertaken in either
        of
        these matters.
 
 FirstEnergy is vigorously defending these actions, but cannot predict the
        outcome of any of these proceedings or whether any further regulatory
        proceedings or legal actions may be initiated against the Companies. Although
        unable to predict the impact of these proceedings, if FirstEnergy or its
        subsidiaries were ultimately determined to have legal liability in connection
        with these proceedings, it could have a material adverse effect on FirstEnergy's
        or its subsidiaries' financial condition, results of operations and cash
        flows.
 
 *Nuclear
        Plant
        Matters*
 
 On January 20, 2006, FENOC announced that it has entered into a deferred
        prosecution agreement with the U.S. Attorney’s Office for the Northern District
        of Ohio and the Environmental Crimes Section of the Environment and Natural
        Resources Division of the DOJ related to FENOC’s communications with the NRC
        during the fall of 2001 in connection with the reactor head issue at the
        Davis-Besse Nuclear Power Station. Under the agreement, which expires on
        December 31, 2006, the United States acknowledged FENOC’s extensive
        corrective actions at Davis-Besse, FENOC’s cooperation during investigations by
        the DOJ and the NRC, FENOC’s pledge of continued cooperation in any related
        criminal and administrative investigations and proceedings, FENOC’s
        acknowledgement of responsibility for the behavior of its employees, and
        its
        agreement to pay a monetary penalty. The DOJ will refrain from seeking an
        indictment or otherwise initiating criminal prosecution of FENOC for all
        conduct
        related to the statement of facts attached to the deferred prosecution
        agreement, as long as FENOC remains in compliance with the agreement, which
        FENOC fully intends to do. FENOC paid a monetary penalty of $28 million
        (which is not deductible for income tax purposes) which reduced First Energy's
        earnings by $0.09 per common share in the fourth quarter of 2005.
 
 On April 21, 2005, the NRC issued a NOV and proposed a $5.45 million
        civil penalty related to the degradation of the Davis-Besse reactor vessel
        head
        issue discussed above. FirstEnergy accrued $2 million for a potential fine
        prior to 2005 and accrued the remaining liability for the proposed fine during
        the first quarter of 2005. On September 14, 2005, FENOC filed its response
        to the NOV with the NRC. FENOC accepted full responsibility for the past
        failure
        to properly implement its boric acid corrosion control and corrective action
        programs. The NRC NOV indicated that the violations do not represent current
        licensee performance. FirstEnergy paid the penalty in the third quarter of
        2005.
        On January 23, 2006, FENOC supplemented its response to the NRC's NOV on
        the Davis-Besse head degradation to reflect the deferred prosecution agreement
        that FENOC had reached with the DOJ.
 
 On August 12, 2004, the NRC notified FENOC that it would increase its
        regulatory oversight of the Perry Nuclear Power Plant as a result of problems
        with safety system equipment over the preceding two years and the licensee's
        failure to take prompt and corrective action. FENOC operates the Perry Nuclear
        Power Plant.
 
 On April 4, 2005, the NRC held a public meeting to discuss FENOC’s
        performance at the Perry Nuclear Power Plant as identified in the NRC's annual
        assessment letter to FENOC. Similar public meetings are held with all nuclear
        power plant licensees following issuance by the NRC of their annual assessments.
        According to the NRC, overall the Perry Nuclear Power Plant operated "in
        a
        manner that preserved public health and safety" even though it remained under
        heightened NRC oversight. During the public meeting and in the annual
        assessment, the NRC indicated that additional inspections will continue and
        that
        the plant must improve performance to be removed from the Multiple/Repetitive
        Degraded Cornerstone Column of the Action Matrix. By an inspection report
        dated
        January 18, 2006, the NRC closed one of the White Findings (related to emergency
        preparedness) which led to the multiple degraded cornerstones.
 
 On September 28, 2005, the NRC sent a CAL to FENOC describing commitments
        that
        FENOC had made to improve the performance at the Perry Plant and stated that
        the
        CAL would remain open until substantial improvement was demonstrated. The
        CAL
        was anticipated as part of the NRC's Reactor Oversight Process. In the NRC's
        2005 annual assessment letter dated March 2, 2006 and associated meetings
        to
        discuss the performance of Perry on March 14, 2006, the NRC again stated
        that the Perry Plant continued to operate in a manner that "preserved public
        health and safety." However, the NRC also stated that increased levels of
        regulatory oversight would continue until sustained improvement in the
        performance of the facility was realized. If performance does not improve,
        the
        NRC has a range of options under the Reactor Oversight Process, from increased
        oversight to possible impact to the plant’s operating authority. Although
        FirstEnergy is unable to predict the impact of the ultimate disposition of
        this
        matter, it could have a material adverse effect on FirstEnergy's or its
        subsidiaries' financial condition, results of operations and cash
        flows.
  12
 *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 PUHCA. Concurrent with this notification,
        FirstEnergy received a subpoena asking for background documents and documents
        related to the restatements and Davis-Besse issues. On December 30, 2004,
        FirstEnergy received a subpoena asking for documents relating to issues raised
        during the SEC's PUHCA examination. On August 24, 2005 additional
        information was requested regarding Davis-Besse-related disclosures, which
        has
        been provided. FirstEnergy has cooperated fully with the informal inquiry
        and
        continues to do so with the formal investigation.
 
 On
        August 22,
        2005, a class action complaint was filed against OE in Jefferson County,
        Ohio
        Common Pleas Court, seeking compensatory and punitive damages to be determined
        at trial based on claims of negligence and eight other tort counts alleging
        damages from W.H. Sammis Plant air emissions. The two named plaintiffs are
        also
        seeking injunctive relief to eliminate harmful emissions and repair property
        damage and the institution of a medical monitoring program for class members.
 
 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 million to the bargaining unit employees. On February 6, 2006, the
        federal court granted a Union motion to dismiss JCP&L's appeal of the award
        as premature. JCP&L will file its appeal again in federal district court
        once the damages associated with this case are identified at an individual
        employee level. JCP&L recognized a liability for the potential
        $16 million award in 2005.
 
 The
        City of Huron
        filed a complaint against OE with the PUCO challenging the ability of electric
        distribution utilities to collect transition charges from a customer of a
        newly-formed municipal electric utility. The complaint was filed on May 28,
        2003, and OE timely filed its response on June 30, 2003. In a related
        filing, the Ohio Companies filed for approval with the PUCO of a tariff that
        would specifically allow the collection of transition charges from customers
        of
        municipal electric utilities formed after 1998. 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 decide 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.
 
 **11.
        -
        REGULATORY MATTERS:**
 
 **RELIABILITY
        INITIATIVES**
  In
        late 2003
        and early 2004, a series of letters, reports and recommendations were issued
        from various entities, including governmental, industry and ad hoc reliability
        entities (PUCO, FERC, NERC and the U.S. - Canada Power System Outage Task
        Force)
        regarding enhancements to regional reliability. In 2004, FirstEnergy completed
        implementation of all actions and initiatives related to enhancing area
        reliability, improving voltage and reactive management, operator readiness
        and
        training and emergency response preparedness recommended for completion in
        2004.
        On July 14, 2004, NERC independently verified that FirstEnergy had
        implemented the various initiatives to be completed by June 30 or summer
        2004, with minor exceptions noted by FirstEnergy, which exceptions are now
        essentially complete. FirstEnergy is proceeding with the implementation of
        the
        recommendations that were to be completed subsequent to 2004 and will continue
        to periodically assess the FERC-ordered Reliability Study recommendations
        for
        forecasted 2009 system conditions, recognizing revised load forecasts and
        other
        changing system conditions which may impact the recommendations. Thus far,
        implementation of the recommendations has not required, nor is expected to
        require, substantial investment in new, or material upgrades to existing
        equipment. The FERC or other applicable government agencies and reliability
        coordinators may, however, take a different view as to recommended enhancements
        or may recommend additional enhancements in the future as the result of adoption
        of mandatory reliability standards pursuant to the EPACT 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.
 
 13
 As a result of outages experienced in JCP&L’s service area in 2002 and 2003,
        the NJBPU had implemented reviews into JCP&L’s service reliability. In 2004,
        the NJBPU adopted a 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 DRA 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. On December 30, 2005, the ALJ recommended
        that
        the PPUC adopt the Joint Petition for Settlement among the parties involved
        in
        the three Companies’ request to amend the distribution reliability benchmarks,
        thereby eliminating the need for full litigation. The ALJ’s recommendation,
        adopting the revised benchmarks and standards, was approved by the PPUC on
        February 9, 2006.
 
 The
        EPACT provides
        for the creation of an ERO to establish and enforce reliability standards
        for
        the bulk power system, subject to FERC review. On February 3, 2006, the FERC
        adopted a rule establishing certification requirements for the ERO, as well
        as
        regional entities envisioned to assume monitoring responsibility for the
        new
        reliability standards. The FERC issued an order on rehearing on March 30,
        2006,
        providing certain clarifications and essentially affirming the
        rule.
 
 The
        NERC has been
        preparing the implementation aspects of reorganizing its structure to meet
        the
        FERC’s certification requirements for the ERO. The NERC made a filing with the
        FERC on April 4, 2006 to obtain certification as the ERO and to obtain FERC
        approval of delegation agreements with regional entities. The new FERC rule
        referred to above, further provides for reorganizing regional reliability
        organizations (regional entities) that would replace the current regional
        councils and for rearranging the relationship with the ERO. The “regional
        entity” may be delegated authority by the ERO, subject to FERC approval, for
        enforcing reliability standards adopted by the ERO and approved by the FERC.
        NERC also made a parallel filing with the FERC April 4, 2006 seeking approval
        of
        mandatory reliability standards. These
        reliability
        standards are based with some modifications, on the current NERC Version
        O
        reliability standards with some additional standards. On May 2, 2006, the
        NERC
        Board of Trustees adopted eight new cyber security standards and thirteen
        additional reliability standards. These standards will become effective on
        June
        1, 2006 and will be filed with the FERC and relevant Canadian authorities
        for
        approval. The
        two filings are
        subject to review and acceptance by the FERC.
 
 The
        ERO filing was
        noticed on April 7, 2006 and comments and interventions were filed on
        May 4, 2006. There is no fixed time for the FERC to act on this filing. The
        reliability standards filing was noticed by FERC on April 18, 2006. In that
        notice FERC announced its intent to treat the proposed reliability standards
        as
        a Notice of Proposed Rulemaking (NOPR), and issue a NOPR in July 2006. Prior
        to
        that time, the FERC staff will release a preliminary assessment of the proposed
        reliability standards. FERC also intends to hold a technical conference on
        the
        proposed reliability standards. A comment period will be set after the Staff
        assessment is released and the technical conference is held. NERC has requested
        an effective date of January 1, 2007 for the reliability standards.
 
 The
        ECAR,
        Mid-Atlantic Area Council, and Mid-American Interconnected Network reliability
        councils have completed the consolidation of these regions into a single
        new
        regional reliability organization known as ReliabilityFirst Corporation.
        ReliabilityFirst began operations as a regional reliability council under
        NERC
        on January 1, 2006 and intends to file and obtain certification consistent
        with the final rule as a “regional entity” under the ERO during 2006. All of
        FirstEnergy’s facilities are located within the ReliabilityFirst
        region.
 
 FirstEnergy believes 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 standards. The financial
        impact of complying with the new standards cannot be determined at this time.
        However, the EPACT required that all prudent costs incurred to comply with
        the
        new reliability standards be recovered in rates.
  14
 
 **OHIO**
 
 On
        October 21, 2003 the Ohio
        Companies filed the RSP case with the PUCO. On August 5, 2004, the Ohio
        Companies accepted the RSP as modified and approved by the PUCO in an August
        4,
        2004 Entry on Rehearing, subject to a CBP. The RSP was intended to establish
        generation service rates beginning January 1, 2006, in response to 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 arguments on the appeals. On May 3, 2006, the Supreme Court of Ohio
        issued
        an opinion affirming that order with respect to the approval of the rate
        stabilization charge, approval of the shopping credits, the grant of interest
        on
        shopping credit incentive deferral amounts, and approval of FirstEnergy’s
        financial separation plan. It remanded the approval of the RSP pricing back
        to
        the PUCO for further consideration of the issue as to whether the RSP, as
        adopted by the PUCO, provided for sufficient customer participation in the
        competitive marketplace.
 
 Under provisions of the RSP, the PUCO had required the Ohio Companies to
        undertake a CBP to secure generation and allow for customer pricing
        participation in the competitive marketplace. Any acceptance of future
        competitive bid results would terminate the RSP pricing, with no accounting
        impacts to the RSP, and not until 12 months after the PUCO authorizes such
        termination. On December 9, 2004, the PUCO rejected the auction price
        results from the CBP for the generation supply period beginning January 1,
        2006
        and issued an entry stating that the pricing under the approved revised RSP
        would take effect on January 1, 2006. On February 23, 2006 the CBP
        auction manager, National Economic Research Associates, notified the PUCO
        that a
        subsequent CBP to potentially provide firm generation service for the Ohio
        Companies' 2007 and 2008 actual load requirements could not proceed due to
        lack
        of interest, as there were no bidder applications submitted. Additionally,
        on
        March 20, 2006, the PUCO denied applications for rehearing filed by various
        parties regarding the PUCO's rules for the CBP. The above May 3, 2006
        Supreme Court of Ohio opinion may require the PUCO to reconsider this
        customer pricing process.
 
 On
        January 4,
        2006, the PUCO approved, with modifications, the Ohio Companies' RCP to
        supplement the RSP to provide customers with more certain rate levels than
        otherwise available under the RSP during the plan period. Major provisions
        of
        the RCP include:
 
 ·
              Maintaining
                  the existing level of base distribution rates through December 31,
                  2008 for OE and TE, and April 30, 2009 for
                  CEI;
 
 ·
              Deferring
                  and
                  capitalizing for future recovery (over a 25-year period) with carrying
                  charges certain distribution costs to be incurred during the period
                  January 1, 2006 through December 31, 2008, not to exceed
                  $150 million in each of the three
                  years;
 
 ·
              Adjusting
                  the
                  RTC and extended RTC recovery periods and rate levels so that full
                  recovery of authorized costs will occur as of December 31, 2008 for
                  OE and TE and as of December 31, 2010 for
                  CEI;
 
 ·
              Reducing
                  the
                  deferred shopping incentive balances as of January 1, 2006 by up to
                  $75 million for OE, $45 million for TE, and $85 million for CEI
                  by accelerating the application of each respective company's accumulated
                  cost of removal regulatory liability;
                  and
 
 ·
              Recovering
                  increased fuel costs (compared to a 2002 baseline) of up to $75
                  million,
                  $77 million, and $79 million, in 2006, 2007, and 2008,
                  respectively, from all OE and TE distribution and transmission
                  customers
                  through a fuel recovery mechanism. OE, TE, and CEI may defer and
                  capitalize (for recovery over a 25-year period) increased fuel
                  costs above
                  the amount collected through the fuel recovery mechanism (in lieu
                  of
                  implementation of the GCAF rider).
 
 The
        PUCO’s January
        4, 2006 approval of the RCP also included approval of the Ohio
        Companies’ supplemental
        stipulation which was filed with the PUCO on November 4, 2005 and which was
        an
        additional component of the RCP filed on September 9, 2005. On
        January 10, 2006, the Ohio Companies filed a Motion for Clarification of
        the PUCO order approving the RCP. The Ohio Companies sought clarity on issues
        related to distribution deferrals, including requirements of the review process,
        timing for recognizing certain deferrals and definitions of the types of
        qualified expenditures. The Ohio Companies also sought confirmation that
        the
        list of deferrable distribution expenditures originally included in the revised
        stipulation fall within the PUCO order definition of qualified expenditures.
        On
        January 25, 2006, the PUCO issued an Entry on Rehearing granting in part,
        and denying in part, the Ohio Companies’ previous requests and clarifying issues
        referred to above. The PUCO granted the Ohio Companies’ requests to:
  15
 
 ·
                  Recognize
                      fuel
                      and distribution deferrals commencing January 1,
                      2006;·
                  Recognize
                      distribution deferrals on a monthly basis prior to review by
                      the PUCO
                      Staff;·
                  Clarify
                      that
                      the types of distribution expenditures included in the Supplemental
                      Stipulation may be deferred; and·
                  Clarify
                      that
                      distribution expenditures do not have to be “accelerated” in order to be
                      deferred.
 The
        PUCO approved
        the Ohio Companies’ methodology for determining distribution deferral amounts,
        but denied the Motion in that the PUCO Staff must verify the level of
        distribution expenditures contained in current rates, as opposed to simply
        accepting the amounts contained in the Ohio Companies’ Motion. On February 3,
        2006, several other parties filed applications for rehearing on the PUCO's
        January 4, 2006 Order. The Ohio Companies responded to the applications for
        rehearing on February 13, 2006. In an Entry on Rehearing issued by the PUCO
        on March 1, 2006, all motions for rehearing were denied. Certain of these
        parties have subsequently filed their notices of appeal with the Supreme
        Court
        of Ohio alleging various errors made by the PUCO in its order approving the
        RCP.
 
 On
        December 30,
        2004, the Ohio Companies filed with the PUCO two applications related to
        the
        recovery of transmission and ancillary service related costs. The first
        application sought recovery of these costs beginning January 1, 2006. The
        Ohio Companies requested that these costs be recovered through a rider that
        would be effective on January 1, 2006 and adjusted each July 1
        thereafter. The parties reached a settlement agreement that was approved
        by the
        PUCO on August 31, 2005. The incremental transmission and ancillary service
        revenues expected to be recovered from January through June 30, 2006 are
        approximately $66 million. This amount includes the recovery of the 2005
        deferred MISO expenses as described below. On May 1, 2006, the Ohio Companies
        filed a modification to the rider to 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 MISO,
        but
        only for those costs incurred during the period December 30, 2004 through
        December 31, 2005. Permission to defer costs incurred prior to
        December 30, 2004 was denied. The PUCO also authorized the Ohio Companies
        to accrue carrying charges on the deferred balances. On August 31, 2005,
        the OCC appealed the PUCO's decision. All briefs have been filed. On March
        20,
        2006, the Ohio Supreme Court, on its own motion, consolidated the OCC's appeal
        of the Ohio Companies' case with a similar case involving Dayton Power &
Light Company. Oral arguments are currently scheduled for May 10,
        2006.
 
 On
        January 20,
        2006 the OCC sought rehearing of the PUCO approval of the recovery of deferred
        costs through the rider during the period January 1, 2006 through June 30,
        2006. The PUCO denied the OCC's application on February 6, 2006. On March
        23, 2006, the OCC appealed the PUCO's order to the Ohio Supreme Court. The
        OCC's
        brief is expected to be filed during the second quarter of 2006. The briefs
        of
        the PUCO and the Ohio Companies will be due within thirty days of the OCC's
        filing. On March 27, 2006, the OCC filed a motion to consolidate this appeal
        with the deferral appeals discussed above and to postpone oral arguments
        in the
        deferral appeal until after all briefs are filed in this most recent appeal
        of
        the rider recovery mechanism. On April 18, 2006, the Court denied both parts
        of
        the motion but on its own motion consolidated the OCC's appeal of the Ohio
        Companies' case with a similar case of Dayton Power & Light Company and
        stayed briefing on these appeals.
 
 **PENNSYLVANIA**
 
 A
        February 2002
        Commonwealth Court of Pennsylvania decision affirmed the June 2001 PPUC decision
        regarding approval of the FirstEnergy/GPU merger, remanded the issues of
        quantification and allocation of merger savings to the PPUC and denied Met-Ed
        and Penelec the rate relief initially approved in the PPUC decision. On
        October 2, 2003, the PPUC issued an order concluding that the Commonwealth
        Court reversed the PPUC’s June 2001 order in its entirety. In accordance
        with the PPUC's direction, Met-Ed and Penelec filed supplements to their
        tariffs
        that became effective in October 2003 and that reflected the CTC rates and
        shopping credits in effect prior to the June 2001 order.
 
 Met-Ed’s
        and
        Penelec’s combined portion of total net merger savings during 2001 - 2004 is
        estimated to be approximately $51 million. A procedural schedule was established
        by the ALJ on January 17, 2006. The companies’ filed initial testimony on
        March 1, 2006. Hearings are currently scheduled for the end of October 2006
        with
        the ALJ’s recommended decision to be issued in February 2007. The companies have
        requested that this proceeding be consolidated with the April 10, 2006
        transition plan filing proceeding as discussed below. Met-Ed and Penelec
        are
        unable to predict the outcome of this proceeding.
  16
 
 In
        an
        October 16, 2003 order, the PPUC approved September 30, 2004 as the
        date for Met-Ed's and Penelec's NUG trust fund refunds. The PPUC order also
        denied their accounting treatment request regarding the CTC rate/shopping
        credit
        swap by requiring Met-Ed and Penelec to treat the stipulated CTC rates that
        were
        in effect from January 1, 2002 on a retroactive basis. On October 22,
        2003, Met-Ed and Penelec filed an Objection with the Commonwealth Court asking
        that the Court reverse this PPUC finding; a Commonwealth Court judge
        subsequently denied their Objection on October 27, 2003 without
        explanation. On October 31, 2003, Met-Ed and Penelec filed an Application
        for Clarification of the Court order with the Commonwealth Court, a Petition
        for
        Review of the PPUC's October 2 and October 16, 2003 Orders, and an
        Application for Reargument, if the judge, in his clarification order, indicates
        that Met-Ed's and Penelec's Objection was intended to be denied on the merits.
        The Reargument Brief before the Commonwealth Court was filed on January 28,
        2005. Oral arguments are scheduled for June 8, 2006.
 
 As
        of March 31,
        2006, Met-Ed's and Penelec's regulatory deferrals pursuant to the 1998
        Restructuring Settlement (including the Phase 2 Proceedings) and the
        FirstEnergy/GPU Merger Settlement Stipulation are $328 million and
        $50 million, respectively. Penelec's $50 million is subject to the pending
        resolution of taxable income issues associated with NUG trust fund proceeds.
 
 On
        January 12, 2005,
        Met-Ed and Penelec filed, before the PPUC, a request for deferral of
        transmission-related costs beginning January 1, 2005. The OCA, OSBA, OTS,
        MEIUG,
        PICA, Allegheny Electric Cooperative and Pennsylvania Rural Electric Association
        have all intervened in the case. As of March 31, 2006, the PPUC had taken
        no
        action on the request and neither company had yet implemented deferral
        accounting for these costs. Met-Ed and Penelec sought to consolidate this
        proceeding (and modified their request to provide deferral of 2006
        transmission-related costs only) with the comprehensive rate filing they
        made on
        April 10, 2006 as described below. On May 4, 2006, the PPUC approved
        the modified request. Accordingly, Met-Ed and Penelec will implement deferral
        accounting for these costs in the second quarter of 2006, which will include
        $24
        million and $4 million, respectively, representing the amounts that were
        incurred in the first quarter of 2006 -- the deferrals of such amounts will
        be reflected in the second quarter of 2006.
 
 Met-Ed
        and Penelec
        purchase a portion of their PLR requirements from FES through a wholesale
        power
        sales agreement. Under this agreement, FES retains the supply obligation
        and the
        supply profit and loss risk for the portion of power supply requirements
        not
        self-supplied by Met-Ed and Penelec under their contracts with NUGs and other
        unaffiliated suppliers. The FES arrangement reduces Met-Ed's and Penelec's
        exposure to high wholesale power prices by providing power at a fixed price
        for
        their uncommitted PLR energy costs during the term of the agreement with
        FES.
        The wholesale power sales agreement with FES could automatically be extended
        for
        each successive calendar year unless any party elects to cancel the agreement
        by
        November 1 of the preceding year. On November 1, 2005, FES and the other
        parties thereto amended the agreement to provide FES the right in 2006 to
        terminate the agreement at any time upon 60 days notice. On April 7, 2006,
        the parties to the wholesale power sales agreement entered into a Tolling
        Agreement that arises out of FES’ notice to Met-Ed and Penelec that FES elected
        to exercise its right to terminate the wholesale power sales agreement effective
        midnight December 31, 2006, because that agreement is not economically
        sustainable to FES.
 
 In
        lieu of allowing
        such termination to become effective as of December 31, 2006, the parties
        agreed, pursuant to the Tolling Agreement, to amend the wholesale power sales
        agreement to provide as follows:
 
 1.  The
        termination
        provisions of the wholesale power sales agreement will be tolled for one
        year
        until December 31, 2007, provided that during such tolling period:
 
 a.
            FES
                will be
                permitted to terminate the wholesale power sales agreement at any
                time
                with sixty days written notice; b.
            Met-Ed
                and
                Penelec will procure through arrangements other than the wholesale
                power
                sales agreement beginning December 1, 2006 and ending December 31,
                2007,
                approximately 33% of the amounts of capacity and energy necessary
                to
                satisfy their PLR obligations for which Committed Resources (i.e.,
                non-utility generation under contract to Met-Ed and Penelec, Met-Ed-
                and
                Penelec-owned generating facilities, purchased power contracts and
                distributed generation) have not been obtained;
                and c.
            FES
                will not
                be obligated to supply additional quantities of capacity and energy
                in the
                event that a supplier of Committed Resources defaults on its supply
                agreement. 
 2.  During
        the tolling
        period FES will not act as agent for Met-Ed or Penelec in procuring the services
        under section 1.(b) above; and
 
 3.  The
        pricing
        provision of the wholesale power sales agreement shall remain unchanged provided
        Met-Ed and Penelec comply with the provisions of the Tolling Agreement and
        any
        applicable provision of the wholesale power sales agreement.
  17
 
 In
        the event that
        FES elects not to terminate the wholesale power sales agreement effective
        midnight December 31, 2007, similar tolling agreements effective after
        December 31, 2007 are expected to be considered by FES for subsequent years
        if
        Met-Ed and Penelec procure through arrangements other than the wholesale
        power
        sales agreement approximately 64%, 83% and 95% of the additional amounts
        of
        capacity and energy necessary to satisfy their PLR obligations for 2008,
        2009
        and 2010, respectively, for which Committed Resources have not been obtained
        from the market.
 
 The
        wholesale power
        sales agreement, as modified by the Tolling Agreement, requires Met-Ed and
        Penelec to satisfy the portion of their PLR obligations currently supplied
        by
        FES from unaffiliated suppliers at prevailing prices, which are likely to
        be
        higher than the current price charged by FES under the current agreement
        and, as
        a result, Met-Ed’s and Penelec’s purchased power costs could materially
        increase. If Met-Ed and Penelec were to replace the entire FES supply at
        current
        market power prices without corresponding regulatory authorization to increase
        their generation prices to customers, each company would likely incur a
        significant increase in operating expenses and experience a material
        deterioration in credit quality metrics. Under such a scenario, each company's
        credit profile would no longer be expected to support an investment grade
        rating
        for its fixed income securities. There can be no assurance, however, that
        if FES
        ultimately determines to terminate, or significantly modify the agreement,
        timely regulatory relief will be granted by the PPUC pursuant to the April
        10,
        2006 comprehensive rate filing discussed below, or, to the extent granted,
        adequate to mitigate such adverse consequences.
 
 Met-Ed
        and Penelec
        made a comprehensive rate filing with the PPUC on April 10, 2006 that
        addresses a number of transmission, distribution and supply issues. If Met-Ed's
        and Penelec's preferred approach involving accounting deferrals is approved,
        the
        filing would increase annual revenues by $216 million and $157 million,
        respectively. That filing includes, among other things, a request to charge
        customers for an increasing amount of market priced power procured through
        a
        competitive bid process as the amount of supply provided under the existing
        FES
        agreement is phased out in accordance with the April 7, 2006 Tolling agreement
        described above. Met-Ed
        and Penelec
        also requested approval of the January 12, 2005 petition for the deferral
        of
        transmission-related costs discussed above, but only for those costs incurred
        during 2006. In this rate filing, Met-Ed and Penelec also requested recovery
        of
        annual transmission and related costs incurred on or after January 1, 2007,
        plus the amortized portion of 2006 costs over a ten-year period, along with
        applicable carrying charges, through an adjustable rider similar to that
        implemented in Ohio. Changes in the
        recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs
        are
        also included in the filing. The filing contemplates a reduction in distribution
        rates for Met-Ed in the amount of $37 million annually and an increase in
        distribution rates for Penelec in the amount of $20 million annually. Although
        the companies have proposed an effective date of June 10, 2006, it is
        expected that the PPUC will suspend the effective date for seven months as
        permitted under Pennsylvania law. Hearings are expected to be scheduled for
        the
        second half of 2006 and a PPUC decision is expected early in the first quarter
        of 2007.
 
 On
        October 11,
        2005, Penn filed a plan with the PPUC to secure electricity supply for its
        customers at set rates following the end of its transition period on
        December 31, 2006. Penn recommended that the RFP process cover the period
        January 1, 2007 through May 31, 2008. Hearings were held on
        January 10, 2006 with main briefs filed on January 27, 2006 and reply
        briefs filed on February 3, 2006. On February 16, 2006, the ALJ issued a
        Recommended Decision to adopt Penn's RFP process with modifications. The
        PPUC
        approved the Recommended Decision with additional modifications on
        April 20, 2006. The approved plan is designed to provide customers with PLR
        service for 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 NUGC rates and market
        sales
        of NUG energy and capacity. As of March 31, 2006, the accumulated deferred
        cost
        balance totaled approximately $558 million. New Jersey law allows for
        securitization of JCP&L's deferred balance upon application by JCP&L and
        a determination by the NJBPU that the conditions of the New Jersey restructuring
        legislation are met. On February 14, 2003, JCP&L filed for approval to
        securitize the July 31, 2003 deferred balance. On December 2, 2005,
        JCP&L filed a request for recovery of $165 million of actual
        above-market NUG costs incurred from August 1, 2003 through
        October 31, 2005 and forecasted above-market NUG costs for November and
        December 2005. On February 1, 2006, the NJBPU selected Bear Stearns as the
        financial advisor. Meetings with the NJBPU Staff and the DRA were held during
        March and April and additional discovery conducted. The DRA filed comments
        on
        April 6, 2006, arguing that the proposed securitization does not produce
        customer savings. JCP&L submitted reply comments on April 10, 2006. On
        February 23, 2006, JCP&L filed updated data reflecting actual amounts
        through December 31, 2005 of $154 million of cost incurred since
        July 31, 2003. The filing also includes a request for recovery of
        $49 million for above-market NUG costs incurred prior to August 1,
        2003, to the extent those costs are not recoverable through securitization.
        On
        March 29, 2006, a pre-hearing conference was held with the presiding ALJ.
        A
        schedule for the proceeding was established, including a discovery period
        and
        evidentiary hearings scheduled for September 2006.
  18
 
 An
        NJBPU Decision
        and Order approving a Phase II Stipulation of Settlement and resolving the
        Motion for Reconsideration of the Phase I Order was issued on May 31, 2005.
        The
        Phase II Settlement includes a performance standard pilot program with potential
        penalties of up to 0.25% of allowable equity return. The Order requires that
        JCP&L file quarterly reliability reports (CAIDI and SAIFI information
        related to the performance pilot program) through December 2006 and updates
        to
        reliability related project expenditures until all projects are completed.
        The
        first quarterly report was submitted to NJBPU on August 16, 2005. The second
        quarterly report was submitted on November 22, 2005. The third quarterly
        report as of December 31, 2005 was submitted on March 28, 2006. As of
        December 31, 2005 there were no performance penalties issued by the
        NJBPU.
 
 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 an NJBPU order for the period June 1, 2005 through
        May 31, 2006.
 
 The
        NJBPU decision
        approving the BGS procurement proposal for the period beginning June 1,
        2006 was issued on October 12, 2005. JCP&L submitted a compliance
        filing on October 26, 2005, which was approved on November 10, 2005.
        The written order was dated December 8, 2005. The auction took place in
        February 2006. On February 9, 2006, the NJBPU approved the auction results
        and a written order was signed on February 23, 2006. The JCP&L tariff
        compliance filing was approved on March 29, 2006. New BGS rates become effective
        June 1, 2006.
 
 In
        a reaction to the
        higher closing prices of the 2006 BGS fixed rate auction, the NJBPU, on
        March 16, 2006, initiated a generic proceeding to evaluate the auction
        process and potential options for the future. On April 6, 2006, initial
        comments were submitted. A public meeting was held on April 21, 2006 and
        a
        legislative-type hearing was held on April 28, 2006. Final comments were
        due on May 4, 2006. An NJBPU decision is anticipated in June 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 DRA filed comments on February 28, 2005
        requesting that decommissioning funding be suspended. On March 18, 2005,
        JCP&L filed a response to those comments. A schedule for further proceedings
        has not yet been set.
 
 On
        August 1,
        2005, the NJBPU established a proceeding to determine whether additional
        ratepayer protections are required at the state level in light of the recent
        repeal of PUHCA under the EPACT. An NJBPU proposed rulemaking to address
        the
        issues was published in the NJ Register on December 19, 2005. The proposal
        would prevent a holding company that owns a gas or electric public utility
        from
        investing more than 25% of the combined assets of its utility and
        utility-related subsidiaries into businesses unrelated to the utility industry.
        A public hearing was held February 7, 2006 and comments were submitted to
        the NJBPU. The
        NJBPU Staff issued a draft proposal on March 31, 2006 addressing various
        issues including access to books and records, ring-fencing, cross subsidization,
        corporate governance and related matters. Comments and reply comments are
        due by
        May 22 and May 31, 2006, respectively. JCP&L is not able to predict the
        outcome of this proceeding at this time.
 
 On
        December 21,
        2005, the NJBPU initiated a generic proceeding and requested comments in
        order
        to formulate an appropriate regulatory treatment for investment tax credits
        related to generation assets divested by New Jersey’s four electric utility
        companies. Comments were filed by the utilities and by the DRA.
 
 **FERC
        MATTERS**
 
 On November 1, 2004, ATSI filed with FERC a request to defer approximately
        $54 million of costs to be incurred from 2004 through 2007 in connection
        with ATSI’s Vegetation Management Enhancement Project (VMEP), which represents
        ATSI’s adoption of newly identified industry “best practices” for vegetation
        management. On March 4, 2005, the FERC approved ATSI’s request to defer the
        VMEP costs (approximately $29 million deferred as of March 31, 2006). On
        March 28, 2006 ATSI and MISO filed with FERC a request to modify ATSI’s
        Attachment O formula rate to include revenue requirements associated with
        recovery of deferred VMEP costs over a five-year period. The requested effective
        date to begin recovery is June 1, 2006. Various parties have filed comments
        responsive to the March 28, 2006 submission. The FERC has not taken any
        action on the filing. The estimated impact of the VMEP cost recovery is
        $13 million in revenues annually during the five-year recovery period of
        June 1, 2006 to May 31, 2011 .
 
 On
        January 24, 2006,
        ATSI and MISO filed with FERC a request to correct ATSI’s Attachment O formula
        rate to reverse revenue credits associated with termination of revenue streams
        from transitional rates stemming from FERC’s elimination of through and out
        rates. Revenues formerly collected under these rates were included in, and
        served to reduce, ATSI’s zonal transmission rate under the Attachment O formula.
        Absent the requested correction, elimination of these revenue streams would
        not
        be fully reflected in ATSI’s formula rate until June 1, 2008. On March 16,
        2006, FERC approved without suspension the revenue credit correction, which
        became effective April 1, 2006. One party sought rehearing of the FERC's
        order.
        The FERC has not yet issued a further order. The estimated impact of the
        correction mechanism is approximately $40 million in revenues on an annualized
        basis beginning June 1, 2006.
  19
 On
        November 18,
        2004, the FERC issued an order eliminating the regional through and out rates
        (RTOR) for transmission service between the MISO and PJM regions. The FERC
        also
        ordered the MISO, PJM and the transmission owners within the MISO and PJM
        to
        submit compliance filings containing a mechanism - the Seams Elimination
        Cost
        Adjustment (SECA) -- to recover lost RTOR revenues during a 16-month transition
        period from load serving entities. The FERC issued orders in 2005 setting
        the
        SECA for hearing. ATSI, JCP&L, Met-Ed, Penelec, and FES continue to be
        involved in the FERC hearings concerning the calculation and imposition of
        the
        SECA charges. The hearing began on May 1, 2006. The FERC has ordered the
        Presiding Judge to issue an initial decision by August 11,
        2006.
  On
        January 31,
        2005, certain PJM transmission owners made three filings with the FERC pursuant
        to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and
        Penelec were parties to that proceeding and joined in two of the filings.
        In the
        first filing, the settling transmission owners submitted a filing justifying
        continuation of their existing rate design within the PJM RTO. In the second
        filing, the settling transmission owners proposed a revised Schedule 12 to
        the PJM tariff designed to harmonize the rate treatment of new and existing
        transmission facilities. Interventions and protests were filed on
        February 22, 2005. In the third filing, Baltimore Gas and Electric Company
        and Pepco Holdings, Inc. requested a formula rate for transmission service
        provided within their respective zones. On May 31, 2005, the FERC issued an
        order on these cases. First, it set for hearing the existing rate design
        and
        indicated that it will issue a final order within six months. American
        Electric
        Power Company, Inc. filed in opposition proposing to create a "postage stamp"
        rate for high voltage transmission facilities across PJM. Second, the FERC
        approved the proposed Schedule 12 rate harmonization. Third, the FERC accepted
        the proposed formula rate, subject to referral and hearing procedures. On
        June 30, 2005, the settling PJM transmission owners filed a request for
        rehearing of the May 31, 2005 order. On
        March 20, 2006 a settlement was filed with FERC in the formula rate
        proceeding that generally accepts the companies' formula rate proposal. The
        FERC
        issued an order approving this settlement on April 19, 2006. If the FERC
        accepts
        AEP's proposal, significant additional transmission revenues would be imposed
        on
        JCP&L, Met-Ed, Penelec, and other transmission zones within
        PJM.
 
 On
        November 1, 2005,
        FES filed two power sales agreements for approval with the FERC. One power
        sales
        agreement provided for FES to provide the PLR requirements of the Ohio Companies
        at a price equal to the retail generation rates approved by the PUCO for
        a
        period of three years beginning January 1, 2006. The Ohio Companies will be
        relieved of their obligation to obtain PLR power requirements from FES if
        the
        Ohio competitive bid process results in a lower price for retail customers.
        A
        similar power sales agreement between FES and Penn permits Penn to obtain
        its
        PLR power requirements from FES at a fixed price equal to the retail generation
        price during 2006. The PPUC approved Penn's plan with modifications on April
        20,
        2006 to use an RFP process to obtain its power supply requirements after
        2006.
 
 On
        December 29,
        2005, the FERC issued an order setting the two power sales agreements for
        hearing. The order criticized the Ohio competitive bid process, and required
        FES
        to submit additional evidence in support of the reasonableness of the prices
        charged in the power sales agreements. A pre-hearing conference was held
        on
        January 18, 2006 to determine the hearing schedule in this case. FES
        expects an initial decision to be issued in this case in late January 2007,
        as a
        result of an April 20, 2006 extension of the procedural schedule. The outcome
        of
        this proceeding cannot be predicted. FES has sought rehearing of the
        December 29, 2005 order and the FERC granted rehearing for further
        consideration on March 1, 2006.
 
 **12.
        - 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, 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. This EITF Issue will not have a material impact on
        FirstEnergy's financial results.
  20
 
 *SFAS
                  155 -
                  “Accounting for Certain Hybrid Financial Instruments-an amendment
                  of FASB
                  Statements No. 133 and 140”*
  In February 2006, the FASB issued SFAS 155 which amends SFAS 133 “Accounting for
        Derivative Instruments and Hedging Activities,” (SFAS 133) and SFAS 140
“Accounting for Transfers and Servicing of Financial Assets and Extinguishments
        of Liabilities.” This Statement permits fair value remeasurement for any hybrid
        financial instrument that contains an embedded derivative that otherwise
        would
        require bifurcation, clarifies which interest-only strips and principal-only
        strips are not subject to the requirements of SFAS 133, establishes a
        requirement to evaluate interests in securitized financial assets to identify
        interests that are freestanding derivatives or that are hybrid financial
        instruments that contain an embedded derivative requiring bifurcation, clarifies
        that concentrations of credit risk in the form of subordination are not embedded
        derivatives and amends SFAS 140 to eliminate the prohibition on a qualifying
        special-purpose entity from holding a derivative financial instrument that
        pertains to a beneficial interest other than another derivative instrument.
        This
        Statement is effective for all financial instruments acquired or issued
        beginning January 1, 2007. FirstEnergy is currently evaluating the impact
        of this Statement on its financial statements.
 
 **13.
        -
        SEGMENT INFORMATION:**
 
 FirstEnergy
        has two
        reportable segments: regulated services and power supply management services.
        The aggregate “Other” segments do not individually meet the criteria to be
        considered a reportable segment. The regulated services segment's operations
        include the regulated sale of electricity and distribution and transmission
        services by its eight utility subsidiaries in Ohio, Pennsylvania and New
        Jersey.
        The power supply management services segment primarily consists of the
        subsidiaries (FES, FGCO, NGC and FENOC) that sell electricity in deregulated
        markets and operate and now own the generation facilities of OE, CEI, TE
        and
        Penn resulting from the deregulation of the Companies' electric generation
        business. “Other” consists of telecommunications services, the recently sold MYR
        (a construction service company) and retail natural gas operations (see Note
        4).
        The assets and revenues for the other business operations are below the
        quantifiable threshold for operating segments for separate disclosure as
        “reportable segments.”
 
 The
        regulated
        services segment designs, constructs, operates and maintains FirstEnergy's
        regulated transmission and distribution systems. Its revenues are primarily
        derived from electricity delivery and transition cost recovery. Assets of
        the
        regulated services segment as of March 31, 2005 included generating units
        that
        were leased or whose output had been sold to the power supply management
        services segment. The regulated services segment’s 2005 internal revenues
        represented the rental revenues for the generating unit leases which ceased
        in
        the fourth quarter of 2005 as a result of the intra-system generation asset
        transfers (see Note 14).
 
 The
        power supply
        management services segment supplies all of the electric power needs of
        FirstEnergy’s end-use customers through retail and wholesale arrangements,
        including regulated retail sales to meet the PLR requirements of FirstEnergy's
        Ohio and Pennsylvania companies and competitive retail sales to commercial
        and
        industrial businesses primarily in Ohio, Pennsylvania and Michigan. This
        business segment owns and operates FirstEnergy's generating facilities and
        purchases electricity from the wholesale market when needed to meet sales
        obligations. The segment's net income is primarily derived from all electric
        generation sales revenues less the related costs of electricity generation,
        including purchased power and net transmission, congestion and ancillary
        costs
        charged by PJM and MISO to deliver energy to retail customers.
 
 Segment
        reporting
        for interim periods in 2005 was reclassified to conform to the current year
        business segment organization and operations and the reclassification of
        discontinued operations (see Note 4). Changes in the current year operations
        reporting reflected in reclassifications of 2005 segment reporting primarily
        includes the transfer of the net results of retail transmission revenues
        and
        PJM/MISO transmission revenues and expenses associated with serving electricity
        load previously included in the regulated services segment to the power supply
        management services segment. In addition, as a result of the 2005 Ohio tax
        legislation reducing the effective state income tax rate, the calculated
        composite income tax rate used in the two reportable segments results for
        2005
        and 2006 has been changed to 40% from the 41% previously reported in their
        2005
        segment results. The net amount of the changes in the 2005 reportable segments'
        income taxes reclassifications has been correspondingly offset in the 2005
        "Reconciling Adjustments." FSG is being disclosed as a reporting segment
        due to
        its subsidiaries qualifying as held for sale. Interest expense on holding
        company debt and corporate support services revenues and expenses are included
        in "Reconciling Adjustments."
 
  21
  
 **Segment
                  Financial Information**
              
              
              
              **Power****Supply****Regulated**
              
              **Management**
              
              **Facilities**
              
              
              
              **Reconciling****Three
                  Months Ended**
              
              **Services**
              
              **Services**
              
              **Services**
              
              **Other**
              
              **Adjustments**
              
              **Consolidated*****(In
                  millions)*****March
                  31, 2006**External
                  revenues
              
              $
              1,083
              
              $
              1,619
              
              $
              46
              
              $
              120
              
              $
              (23
              )
              $
              2,845Internal
                  revenues
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Total
                  revenues
              
              
              1,083
              
              
              1,619
              
              
              46
              
              
              120
              
              
              (23
              )
              
              2,845Depreciation
                  and amortization
              
              
              259
              
              
              46
              
              
              -
              
              
              1
              
              
              5
              
              
              311Investment
                  Income
              
              
              62
              
              
              15
              
              
              -
              
              
              -
              
              
              (34
              )
              
              43Net
                  interest
                  charges
              
              
              93
              
              
              49
              
              
              -
              
              
              1
              
              
              17
              
              
              160Income
                  taxes
              
              
              144
              
              
              27
              
              
              -
              
              
              (7
              )
              
              (30
              )
              
              134Net
                  income
              
              
              211
              
              
              40
              
              
              (1
              )
              
              15
              
              
              (44
              )
              
              221Total
                  assets
              
              
              23,848
              
              
              6,759
              
              
              63
              
              
              304
              
              
              823
              
              
              31,797Total
                  goodwill
              
              
              5,916
              
              
              24
              
              
              -
              
              
              -
              
              
              -
              
              
              5,940Property
                  additions
              
              
              195
              
              
              244
              
              
              -
              
              
              1
              
              
              7
              
              
              447**March
                  31, 2005**External
                  revenues
              
              $
              1,216
              
              $
              1,377
              
              $
              43
              
              $
              112
              
              $
              2
              
              $
              2,750Internal
                  revenues
              
              
              78
              
              
              -
              
              
              -
              
              
              -
              
              
              (78
              )
              
              -Total
                  revenues
              
              
              1,294
              
              
              1,377
              
              
              43
              
              
              112
              
              
              (76
              )
              
              2,750Depreciation
                  and amortization
              
              
              374
              
              
              13
              
              
              -
              
              
              1
              
              
              6
              
              
              394Investment
                  income
              
              
              41
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              41Net
                  interest
                  charges
              
              
              98
              
              
              10
              
              
              -
              
              
              1
              
              
              62
              
              
              171Income
                  taxes
              
              
              157
              
              
              (30
              )
              
              (3
              )
              
              10
              
              
              (13
              )
              
              121Income
                  before
                  discontinued operations
              
              
              236
              
              
              (46
              )
              
              (2
              )
              
              5
              
              
              (52
              )
              
              141Discontinued
                  operations
              
              
              -
              
              
              -
              
              
              13
              
              
              6
              
              
              -
              
              
              19Net
                  income
              
              
              236
              
              
              (46
              )
              
              11
              
              
              11
              
              
              (52
              )
              
              160Total
                  assets
              
              
              28,540
              
              
              1,582
              
              
              83
              
              
              495
              
              
              561
              
              
              31,261Total
                  goodwill
              
              
              5,947
              
              
              24
              
              
              -
              
              
              63
              
              
              -
              
              
              6,034Property
                  additions
              
              
              141
              
              
              81
              
              
              1
              
              
              2
              
              
              4
              
              
              229
  Reconciling
        adjustments to segment operating results from internal management reporting
        to
        consolidated external financial reporting primarily consist of interest expense
        related to holding company debt, corporate support services revenues and
        expenses, fuel marketing revenues (which are reflected as reductions to expenses
        for internal management reporting purposes) and elimination of intersegment
        transactions.
 
 **14.
        -
        FIRSTENERGY INTRA-SYSTEM GENERATION ASSET TRANSFERS**
 
 On
        May 13,
        2005, Penn, and on May 18, 2005, the Ohio Companies, entered into certain
        agreements implementing a series of intra-system generation asset transfers
        that
        were completed in the fourth quarter of 2005. The asset transfers resulted
        in
        the respective undivided ownership interests of the Ohio Companies and Penn
        in
        FirstEnergy’s nuclear and non-nuclear generation assets being owned by NGC and
        FGCO, respectively. The generating plant interests transferred do not include
        leasehold interests of CEI, TE and OE in certain of the plants that are
        currently subject to sale and leaseback arrangements with non-affiliates.
 
 On
        October 24, 2005,
        the Ohio Companies and Penn completed the intra-system transfer of non-nuclear
        generation assets to FGCO. Prior to the transfer, FGCO, as lessee under a
        Master
        Facility Lease with the Ohio Companies and Penn, leased, operated and maintained
        the non-nuclear generation assets that it now owns. The asset transfers were
        consummated pursuant to FGCO's purchase option under the Master Facility
        Lease.
 
 On
        December 16,
        2005, the Ohio Companies and Penn completed the intra-system transfer of
        their
        respective ownership in the nuclear generation assets to NGC through, in
        the
        case of OE and Penn, an asset spin-off by way of dividend and, in the case
        of
        CEI and TE, a sale at net book value. FENOC continues to operate and maintain
        the nuclear generation assets.
 
 These
        transactions
        were pursuant to the Ohio Companies’ and Penn’s restructuring plans that were
        approved by the PUCO and the PPUC, respectively, under applicable Ohio and
        Pennsylvania electric utility restructuring legislation. Consistent with
        the
        restructuring plans, generation assets that had been owned by the Ohio Companies
        and Penn were required to be separated from the regulated delivery business
        of
        those companies through transfer to a separate corporate entity. The
        transactions essentially completed the divestitures contemplated by the
        restructuring plans by transferring the ownership interests to NGC and FGCO
        without impacting the operation of the plants.
  22
 
 **15.
        -
        JCP&L RESTATEMENT**
 
 JCP&L's earnings for the three months ended March 31, 2005 have been
        restated to reflect the results of a tax audit by the State of New Jersey,
        in
        which JCP&L became aware that the New Jersey Transitional Energy Facilities
        Assessment (TEFA) is not an allowable deduction for state income tax purposes.
        JCP&L had incorrectly claimed a state income tax deduction for TEFA payments
        and as a result, income taxes and interest expense were understated by
        $0.5 million and $0.6 million, respectively, in the first quarter of 2005.
        The effects of these adjustments on JCP&L's Consolidated Statements of
        Income for the three months ended March 31, 2005 are as follows:
 
 **As
                  Previously**
              
              **As****Reported**
              
              **Restated*****(In
                  millions)***Operating
                  Revenues
              
              $
              529.1
              
              $
              529.1Operating
                  Expenses andTaxes
              
              
              494.7
              
              
              495.2Operating
                  Income
              
              
              34.4
              
              
              33.9Net
                  Interest
                  Charges
              
              
              19.9
              
              
              20.5Net
                  Income
              
              $
              14.5
              
              $
              13.4Earnings
                  Applicableto
                  Common
                  Stock
              
              $
              14.4
              
              $
              13.3
 
 These
        adjustments
        were not material to FirstEnergy's consolidated financial statements, nor
        JCP&L's Consolidated Balance Sheets or Consolidated Statements of Cash
        Flows.
  23
  **FIRSTENERGY
                    CORP.****CONSOLIDATED
                    STATEMENTS OF INCOME****(Unaudited)****Three
                    Months Ended****March
                    31,****2006**
                
                **2005*****(In millions, except per share
                    amounts)*****REVENUES:**Electric
                    utilities
                
                $
                2,340
                
                $
                2,267Unregulated
                    businesses
                
                
                505
                
                
                483Total revenues
                
                
                2,845
                
                
                2,750**EXPENSES:**Fuel
                    and
                    purchased power
                
                
                976
                
                
                895Other
                    operating expenses
                
                
                893
                
                
                884Provision
                    for
                    depreciation
                
                
                148
                
                
                143Amortization
                    of regulatory assets
                
                
                222
                
                
                311Deferral
                    of
                    new regulatory assets
                
                
                (59
                )
                
                (60
                )General
                    taxes
                
                
                193
                
                
                185Total expenses
                
                
                2,373
                
                
                2,358**OPERATING
                    INCOME**
                
                
                472
                
                
                392**OTHER
                    INCOME (EXPENSE)**Investment
                    income
                
                
                43
                
                
                41Interest
                    expense
                
                
                (165
                )
                
                (164
                )Capitalized
                    interest
                
                
                7
                
                
                -Subsidiaries’
                    preferred stock dividends
                
                
                (2
                )
                
                (7
                )Total other income (expense)
                
                
                (117
                )
                
                (130
                )**INCOME
                    TAXES**
                
                
                134
                
                
                121**INCOME
                    BEFORE DISCONTINUED OPERATIONS**
                
                
                221
                
                
                141Discontinued
                    operations (net of income tax benefit of $8 million)(Note
                    4)
                
                
                -
                
                
                19**NET
                    INCOME**
                
                $
                221
                
                $
                160**BASIC
                    EARNINGS PER SHARE OF COMMON STOCK:**Income
                    before
                    discontinued operations
                
                $
                0.67
                
                $
                0.43Discontinued
                    operations (Note 4)
                
                
                -
                
                
                0.06Net
                    income
                
                $
                0.67
                
                $
                0.49**WEIGHTED
                    AVERAGE NUMBER OF BASIC SHARES OUTSTANDING**
                
                
                329
                
                
                328**DILUTED
                    EARNINGS PER SHARE OF COMMON STOCK:**Income
                    before
                    discontinued operations
                
                $
                0.67
                
                $
                0.42Discontinued
                    operations (Note 4)
                
                
                -
                
                
                0.06Net
                    income
                
                $
                0.67
                
                $
                0.48**WEIGHTED
                    AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING**
                
                
                330
                
                
                329**DIVIDENDS
                    DECLARED PER SHARE OF COMMON STOCK**
                
                $
                0.45
                
                $
                0.4125The
                    preceding
                    Notes to Consolidated Financial Statements as they relate to
                    FirstEnergy
                    Corp. are an integral partof
                    these
                    statements.
   24
   **FIRSTENERGY
                    CORP.****CONSOLIDATED
                    STATEMENTS OF COMPREHENSIVE INCOME****(Unaudited)****Three
                    Months Ended****March
                    31,****2006**
                
                
                
                **2005*****(In
                    millions)*****NET
                    INCOME**
                
                $
                221
                
                
                
                
                $
                160**OTHER
                    COMPREHENSIVE INCOME (LOSS):**Unrealized
                    gain on derivative hedges
                
                
                43
                
                
                
                
                
                7Unrealized
                    gain (loss) on available for sale securities
                
                
                36
                
                
                
                
                
                (8
                )Other
                    comprehensive income (loss)
                
                
                79
                
                
                
                
                
                (1
                )Income
                    tax
                    expense related to other comprehensive income
                
                
                32
                
                
                
                
                
                -Other
                    comprehensive income (loss), net of tax
                
                
                47
                
                
                
                
                
                (1
                )**COMPREHENSIVE
                    INCOME**
                
                $
                268
                
                
                
                
                $
                159The
                    preceding
                    Notes to Consolidated Financial Statements as they relate to
                    FirstEnergy
                    Corp. are an integralpart
                    of these
                    statements.
   25
 
 **FIRSTENERGY
                    CORP.****CONSOLIDATED
                    BALANCE SHEETS****(Unaudited)****March
                    31,**
                
                **December
                    31,****2006**
                
                **2005*****(In
                    millions)*****ASSETS****CURRENT
                    ASSETS:**Cash
                    and cash
                    equivalents
                
                $
                28
                
                $
                64Receivables
                    -Customers
                    (less accumulated provisions of $37 million and$38
                    million,
                    respectively, for uncollectible accounts)
                
                
                1,072
                
                
                1,293Other
                    (less
                    accumulated provisions of $27 millionfor
                    uncollectible accounts in both periods)
                
                
                154
                
                
                205Materials
                    and
                    supplies, at average cost
                
                
                610
                
                
                518Prepayments
                    and other
                
                
                235
                
                
                2372,099
                
                
                2,317**PROPERTY,
                    PLANT AND EQUIPMENT:**In
                    service
                
                
                23,071
                
                
                22,893Less
                    -
                    Accumulated provision for depreciation
                
                
                9,859
                
                
                9,79213,212
                
                
                13,101Construction
                    work in progress
                
                
                1,073
                
                
                89714,285
                
                
                13,998**INVESTMENTS:**Nuclear
                    plant
                    decommissioning trusts
                
                
                1,818
                
                
                1,752Investments
                    in
                    lease obligation bonds
                
                
                845
                
                
                890Other
                
                
                805
                
                
                7653,468
                
                
                3,407**DEFERRED
                    CHARGES AND OTHER ASSETS:**Goodwill
                
                
                5,940
                
                
                6,010Regulatory
                    assets
                
                
                4,396
                
                
                4,486Prepaid
                    pension costs
                
                
                1,018
                
                
                1,023Other
                
                
                591
                
                
                60011,945
                
                
                12,119$
                31,797
                
                $
                31,841**LIABILITIES
                    AND CAPITALIZATION****CURRENT
                    LIABILITIES:**Currently
                    payable long-term debt
                
                $
                2,115
                
                $
                2,043Short-term
                    borrowings
                
                
                931
                
                
                731Accounts
                    payable
                
                
                612
                
                
                727Accrued
                    taxes
                
                
                803
                
                
                800Other
                
                
                989
                
                
                1,1525,450
                
                
                5,453**CAPITALIZATION:**Common
                    stockholders’ equity -Common
                    stock,
                    $.10 par value, authorized 375,000,000 shares -329,836,276
                    shares outstanding
                
                
                33
                
                
                33Other
                    paid-in
                    capital
                
                
                7,050
                
                
                7,043Accumulated
                    other comprehensive income (loss)
                
                
                27
                
                
                (20
                )Retained
                    earnings
                
                
                2,232
                
                
                2,159Unallocated
                    employee stock ownership plan common stock -1,167,865
                    and
                    1,444,796 shares, respectively
                
                
                (22
                )
                
                (27
                )Total
                    common
                    stockholders' equity
                
                
                9,320
                
                
                9,188Preferred
                    stock of consolidated subsidiaries
                
                
                154
                
                
                184Long-term
                    debt
                    and other long-term obligations
                
                
                8,004
                
                
                8,15517,478
                
                
                17,527**NONCURRENT
                    LIABILITIES:**Accumulated
                    deferred income taxes
                
                
                2,759
                
                
                2,726Asset
                    retirement obligations
                
                
                1,148
                
                
                1,126Power
                    purchase
                    contract loss liability
                
                
                1,184
                
                
                1,226Retirement
                    benefits
                
                
                1,334
                
                
                1,316Lease
                    market
                    valuation liability
                
                
                830
                
                
                851Other
                
                
                1,614
                
                
                1,6168,869
                
                
                8,861**COMMITMENTS,
                    GUARANTEES AND CONTINGENCIES (Note 10)**$
                31,797
                
                $
                31,841The
                    preceding
                    Notes to Consolidated Financial Statements as they relate to
                    FirstEnergy
                    Corp. are an integral part ofthese
                    balance
                    sheets.
   26
 
 **FIRSTENERGY
                    CORP.****CONSOLIDATED
                    STATEMENTS OF CASH FLOWS****(Unaudited)****Three
                    Months Ended****March
                    31,****2006**
                
                **2005*****(In
                    millions)*****CASH
                    FLOWS FROM OPERATING ACTIVITIES:**Net
                    income
                
                $
                221
                
                $
                160Adjustments
                    to
                    reconcile net income to net cash from operating activities
                    -Provision
                    for
                    depreciation
                
                
                148
                
                
                143Amortization
                    of regulatory assets
                
                
                222
                
                
                311Deferral
                    of
                    new regulatory assets
                
                
                (59
                )
                
                (60
                )Nuclear
                    fuel
                    and lease amortization
                
                
                20
                
                
                19Deferred
                    purchased power and other costs
                
                
                (125
                )
                
                (118
                )Deferred
                    income taxes and investment tax credits, net
                
                
                6
                
                
                (14
                )Deferred
                    rents
                    and lease market valuation liability
                
                
                (38
                )
                
                (36
                )Accrued
                    compensation and retirement benefits
                
                
                (19
                )
                
                (26
                )Commodity
                    derivative transactions, net
                
                
                26
                
                
                4Income
                    from
                    discontinued operations
                
                
                -
                
                
                (19
                )Cash
                    collateral
                
                
                (106
                )
                
                2Decrease
                    (Increase) in operating assets -Receivables
                
                
                226
                
                
                91Materials
                    and
                    supplies
                
                
                (52
                )
                
                7Prepayments
                    and other current assets
                
                
                (15
                )
                
                (106
                )Increase
                    (Decrease) in operating liabilities -Accounts
                    payable
                
                
                (114
                )
                
                61Accrued
                    taxes
                
                
                8
                
                
                41Accrued
                    interest
                
                
                100
                
                
                108Electric
                    service prepayment programs
                
                
                (14
                )
                
                (5
                )Other
                
                
                (33
                )
                
                35Net
                    cash
                    provided from operating activities
                
                
                402
                
                
                598**CASH
                    FLOWS FROM FINANCING ACTIVITIES:**New
                    Financing
                    -Short-term
                    borrowings, net
                
                
                200
                
                
                140Redemptions
                    and Repayments -Preferred
                    stock
                
                
                (30
                )
                
                (98
                )Long-term
                    debt
                
                
                (64
                )
                
                (236
                )Net
                    controlled
                    disbursement activity
                
                
                (8
                )
                
                (30
                )Common
                    stock
                    dividend payments
                
                
                (148
                )
                
                (135
                )Net
                    cash used
                    for financing activities
                
                
                (50
                )
                
                (359
                )**CASH
                    FLOWS FROM INVESTING ACTIVITIES:**Property
                    additions
                
                
                (447
                )
                
                (229
                )Proceeds
                    from
                    asset sales
                
                
                57
                
                
                54Proceeds
                    from
                    nuclear decommissioning trust fund sales
                
                
                481
                
                
                366Investments
                    in
                    nuclear decommissioning trust funds
                
                
                (484
                )
                
                (391
                )Cash
                    investments
                
                
                25
                
                
                27Other
                
                
                (20
                )
                
                (38
                )Net
                    cash used
                    for investing activities
                
                
                (388
                )
                
                (211
                )Net
                    increase
                    (decrease) in cash and cash equivalents
                
                
                (36
                )
                
                28Cash
                    and cash
                    equivalents at beginning of period
                
                
                64
                
                
                53Cash
                    and cash
                    equivalents at end of period
                
                $
                28
                
                $
                81The
                    preceding
                    Notes to Consolidated Financial Statements as they relate to
                    FirstEnergy
                    Corp. are an integral part ofthese
                    statements.
   27
  
 ***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 March 31, 2006 and the related consolidated statements
        of income, comprehensive income and cash flows for each of the three-month
        periods ended March 31, 2006 and 2005. These interim financial statements
        are
        the responsibility of the Company’s management.
 
 We
        conducted our
        review in accordance with the standards of the Public Company Accounting
        Oversight Board (United States). A review of interim financial information
        consists principally of applying analytical procedures and making inquiries
        of
        persons responsible for financial and accounting matters. It is substantially
        less in scope than an audit conducted in accordance with the standards of
        the
        Public Company Accounting Oversight Board, the objective of which is the
        expression of an opinion regarding the financial statements taken as a whole.
        Accordingly, we do not express such an opinion.
 
 Based
        on our review,
        we are not aware of any material modifications that should be made to the
        accompanying consolidated interim financial statements for them to be in
        conformity with accounting principles generally accepted in the United States
        of
        America.
 
 We
        previously
        audited, in accordance with the standards of the Public Company Accounting
        Oversight Board (United States), the consolidated balance sheet as of December
        31, 2005, and the related consolidated statements of income, capitalization,
        common stockholders’ equity, preferred stock, cash flows and taxes for the year
        then ended, management’s assessment of the effectiveness of the Company’s
        internal control over financial reporting as of December 31, 2005 and the
        effectiveness of the Company’s internal control over financial reporting as of
        December 31, 2005; and in our report (which contained references to the
        Company’s change in its method of accounting for asset retirement obligations as
        of January 1, 2003 and conditional asset retirement obligations as of December
        31, 2005 as discussed in Note 2(K) and Note 12 to those consolidated financial
        statements and the Company’s change in its method of accounting for the
        consolidation of variable interest entities as of December 31, 2003 as discussed
        in Note 7 to those consolidated financial statements) dated February 27,
        2006,
        we expressed unqualified opinions thereon. The consolidated financial statements
        and management’s assessment of the effectiveness of internal control over
        financial reporting referred to above are not presented herein. In our opinion,
        the information set forth in the accompanying consolidated balance sheet
        as of
        December 31, 2005, is fairly stated in all material respects in relation
        to the
        consolidated balance sheet from which it has been derived.
 
 
 
 
 PricewaterhouseCoopers
        LLP
 Cleveland,
        Ohio
 May
        8,
        2006
  28
  **FIRSTENERGY
        CORP.**
 
 **MANAGEMENT’S
        DISCUSSION AND ANALYSIS OF**
 **RESULTS
        OF
        OPERATIONS AND FINANCIAL CONDITION**
 
 
 **EXECUTIVE
        SUMMARY**
 
 Net
        income in the
        first quarter of 2006 was $221 million, or basic and diluted earnings of
        $0.67
        per share of common stock, compared with net income of $160 million, or basic
        earnings of $0.49 per share of common stock ($0.48 diluted) for the first
        quarter of 2005. Total revenues for the first quarter of 2006 were $2.84
        billion, up from $2.75 billion as adjusted to reflect certain businesses
        divested in the first quarter of 2005. Certain businesses divested in the
        first
        quarter of 2005 have been classified as discontinued operations on the
        Consolidated Statements of Income (see Note 4). FirstEnergy’s earnings increase
        was driven primarily by increased electric sales revenues, reduced financing
        costs and reduced transition cost amortization for FirstEnergy's Ohio
        Companies.
 
 Total
        electric generation KWH sales were up by 2.1 percent over the prior-year
        quarter, mostly due to the return of customers to the Ohio Companies from
        third-party suppliers leaving the Ohio marketplace. Electric distribution
        deliveries were down 2.6 percent during the same time period, reflecting
        milder weather conditions in 2006.
 
 FirstEnergy's generating fleet produced a record 20.1 billion KWH during
        the
        first quarter of 2006 compared to 18.8 billion KWH in the first quarter of
        2005. FirstEnergy's non-nuclear fleet produced a record 13.4 billion KWH,
        while
        its nuclear facilities produced 6.7 billion KWH.
  Ohio CBP - On February 23, 2006, the CBP auction manager, National Economic
        Research Associates, notified the PUCO that the CBP to potentially provide
        firm
        generation service for the Ohio Companies’ 2007 and 2008 actual load
        requirements could not proceed due to lack of interest, as there were no
        bidder
        applications submitted. Additionally, on March 16, 2006, the PUCO denied
        applications for rehearing filed by various parties regarding the PUCO’s rules
        for the CBP.
 
 On May 3, 2006, the Supreme Court of Ohio, in a ruling on certain appeals
        filed
        by the OCC and NOAC, issued an opinion affirming PUCO's June 2004 order with
        respect to the approval of the rate stabilization charge, approval of the
        shopping credits, the grant of interest on shopping credit incentive deferral
        amounts and approval of FirstEnergy's financial separation plan. It remanded
        the
        approval of the rate stabilization plan pricing back to the PUCO for further
        consideration of the issue as to whether the rate stabilization plan, as
        adopted
        by the PUCO, provided for sufficient customer participation.
 
 Wind Power Generation - In March 2006, FirstEnergy entered into multi-year
        agreements to purchase a combined 330 MW of wind power output from three
        wind
        power generation projects. Two of the projects are being developed in West
        Virginia, and the third is being developed in central Pennsylvania. The projects
        are anticipated to be complete and operational in 2007. When combined with
        prior
        contracts, these new contracts will bring the total wind power generation
        output
        available to FirstEnergy to 360 MW.
 
 Pennsylvania Rate Matters - On April 10, 2006, FirstEnergy's subsidiaries,
        Met-Ed and Penelec, filed with the PPUC a comprehensive transition rate plan.
        The filing addresses transmission, distribution and power supply issues while
        ensuring that customers continue to pay below-market prices for generation
        through 2010.
 
 Met-Ed requested an overall revenue increase of $216 million, or 19 percent,
        for
        2007 if its preferred approach of implementing accounting deferrals in its
        filing is approved. Under an alternative proposed approach, the 2007 increase
        could be up to $269 million, or 24 percent. Met-Ed also has proposed changes
        in
        its generation rates for the years 2008, 2009 and 2010 that could increase
        revenues by up to $165 million per year.
 
 Penelec requested an overall revenue increase of $157 million, or 15 percent,
        for 2007 if its preferred approach of implementing accounting deferrals in
        its
        filing is approved. Under an alternative proposed approach that assumes
        accounting deferrals are not approved and instead adjusts rates to provide
        for
        appropriate cost recovery, the 2007 increase could be up to $206 million,
        or 19
        percent. Penelec also has proposed changes in its generation rates for 2008,
        2009 and 2010 that could increase revenues by up to $135 million per
        year.
 
 Statutory generation rate caps imposed by Pennsylvania’s 1996 Electricity
        Generation Choice and Competition Act expired as of year-end 2005. While
        Met-Ed's and Penelec's 1998 restructuring plans implemented under that act
        contain additional price caps for generation through 2010, Met-Ed and Penelec
        also incorrectly anticipated that by mid-2003 they would only serve 20 percent
        of their PLR customers’ generation needs. However, Met-Ed and Penelec continue
        to serve virtually all of their PLR customers at these capped rates that
        have
        been and continue to be, well below market prices.
  29
 
 The transmission portion of each transition rate plan filed with the PPUC
        represents nearly one-half of the overall requested increase and reflects
        the
        pass-through of federally mandated charges for transmission services from
        PJM.
        Without regulatory relief, the charges Met-Ed and Penelec expect to pay in
        2006
        will exceed what they expect to collect from customers by an estimated $186
        million (Met-Ed - $131 million; Penelec - $55 million).
 
 With respect to the generation portion of customers' bills, the plan includes
        a
        four-year transition toward market-based generation rates. During this time,
        customers would continue paying below-market prices for power. Under the
        transition plan, the market-priced portion of the generation supply that
        Met-Ed
        and Penelec procure for customers would gradually increase through
        2010.
 
 The transition plan also proposes to defer, for future recovery, costs that
        Met-Ed and Penelec are required to incur under federal law for power purchased
        from NUGs for which there is currently inadequate recovery. The amount of
        these
        costs - above what Met-Ed and Penelec currently collect from customers -
        is
        expected to total approximately $92 million in 2006. However, the deferral
        would begin with costs incurred after new rates become effective.
 
 Met-Ed and Penelec had filed on January 12, 2005 with the PPUC, a request
        for
        deferral of transmission-related costs beginning January 1, 2005. As of March
        31, 2006, the PPUC had taken no action on the request and neither company
        had
        yet implemented deferral accounting for these costs. Met-Ed and Penelec sought
        to consolidate this proceeding (and modified their request to provide deferral
        of 2006 transmission-related costs only) with the April 10, 2006
        comprehensive rate filing. On May 4, 2006, the PPUC approved the modified
        request. Accordingly, Met-Ed and Penelec will implement deferral accounting
        for
        these costs in the second quarter of 2006, which will include $24 million
        and $4 million, respectively, representing the amounts were incurred
        in the first quarter of 2006 -- the deferrals of such amounts will be reflected
        in the second quarter of 2006.
 
 Nuclear
        Outages -
        Beaver Valley Unit 1 returned to service on April 19, 2006, restarting 11
        days
        ahead of schedule from a refueling and maintenance outage. The unit was the
        first plant in the world to have a temporary opening cut in its containment
        building and have its steam generators and reactor head replaced within a
        65-day
        time frame. The Beaver Valley Project also included replacing the turbine
        rotor,
        rewinding the main generator, and replacing approximately one-third of the
        fuel
        assemblies.
 
 Davis-Besse
        returned
        to service on April 27, 2006 from an outage to refuel the plant and to modify
        it
        to generate more electricity. Work performed during the outage, which began
        on
        March 6, 2006, included refurbishing the plant's turbine and rebuilding two
        of
        the four reactor coolant pumps. Generating capacity is expected to increase
        by
        approximately 11 MW to a gross output of about 946 MW.
 
 Penn
        RFP - On April
        20, 2006 the PPUC approved Penn's PLR supply plan with modifications. The
        approved plan encourages wholesale electric suppliers to participate in an
        RFP
        process to provide customers with generation service from January 1, 2007,
        through May 13, 2008. Penn's PLR rates are currently capped at prices determined
        through restructuring agreements that are set to expire at the end of 2006.
        The
        PPUC is obligated to approve a PLR plan with rates that reflect prevailing
        market prices and that allow Penn to recover all reasonable costs for
        service.
 
 **FIRSTENERGY’S
        BUSINESS**
  FirstEnergy
        is a
        public utility holding company headquartered in Akron, Ohio that operates
        primarily through two core business segments (see Results of
        Operations).
 
 ·  **Regulated
        Services** transmits and
        distributes electricity through FirstEnergy's eight utility operating companies
        that collectively comprise the nation’s fifth largest investor-owned electric
        system, serving 4.5 million customers within 36,100 square miles of Ohio,
        Pennsylvania and New Jersey. This business segment derives its revenue
        principally from the delivery of electricity generated or purchased by the
        Power
        Supply Management Services segment in the states in which the utility
        subsidiaries operate.
 
 ·  **Power
        Supply
        Management**  **Services** supplies all of the
        electric power needs of end-use customers through retail and wholesale
        arrangements, including regulated retail sales to meet the PLR requirements
        of
        FirstEnergy's Ohio and Pennsylvania utility subsidiaries and competitive
        retail
        sales to commercial and industrial businesses primarily in Ohio, Pennsylvania
        and Michigan. This business segment owns and operates FirstEnergy's generating
        facilities and purchases electricity from the wholesale market to meet sales
        obligations. The segment's net income is primarily derived from electric
        generation sales revenues less the related costs of electricity generation,
        including purchased power, and net transmission, congestion and ancillary
        costs
        charged by PJM and MISO to deliver energy to retail customers.
  30
  
 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 its remaining non-core businesses (see
        Note 4). The assets and revenues for the other business operations are
        below the quantifiable threshold for separate disclosure as “reportable
        operating segments”.
 
 **FIRSTENERGY
        INTRA-SYSTEM GENERATION ASSET TRANSFERS**
  On
        May 13,
        2005, Penn, and on May 18, 2005, the Ohio Companies entered into certain
        agreements implementing a series of intra-system generation asset transfers
        that
        were completed in the fourth quarter of 2005. The asset transfers resulted
        in
        the respective undivided ownership interests of the Ohio Companies and Penn
        in
        FirstEnergy’s nuclear and non-nuclear generation assets being owned by NGC and
        FGCO, respectively. The generating plant interests transferred do not include
        leasehold interests of CEI, TE and OE in certain of the plants that are
        currently subject to sale and leaseback arrangements with non-affiliates.
 
 On
        October 24, 2005,
        the Ohio Companies and Penn completed the intra-system transfer of non-nuclear
        generation assets to FGCO. Prior to the transfer, FGCO, as lessee under a
        Master
        Facility Lease with the Ohio Companies and Penn, leased, operated and maintained
        the non-nuclear generation assets that it now owns. The asset transfers were
        consummated pursuant to FGCO's purchase option under the Master Facility
        Lease.
 
 On
        December 16,
        2005, the Ohio Companies and Penn completed the intra-system transfer of
        their
        respective ownership in the nuclear generation assets to NGC through, in
        the
        case of OE and Penn, an asset spin-off by way of dividend and, in the case
        of
        CEI and TE, a sale at net book value. FENOC continues to operate and maintain
        the nuclear generation assets.
 
 These
        transactions
        were pursuant to the Ohio Companies’ and Penn’s restructuring plans that were
        approved by the PUCO and the PPUC, respectively, under applicable Ohio and
        Pennsylvania electric utility restructuring legislation. Consistent with
        the
        restructuring plans, generation assets that had been owned by the Ohio Companies
        and Penn were required to be separated from the regulated delivery business
        of
        those companies through transfer to a separate corporate entity. The
        transactions essentially completed the divestitures contemplated by the
        restructuring plans by transferring the ownership interests to NGC and FGCO
        without impacting the operation of the plants. The transfers were intercompany
        transactions and, therefore, had no impact on our consolidated
        results.
 
 **RESULTS
        OF
        OPERATIONS**
 
 The financial results discussed below include revenues and expenses from
        transactions among FirstEnergy's business segments. A reconciliation of segment
        financial results is provided in Note 13 to the consolidated financial
        statements. The FSG business segment is included in “Other and Reconciling
        Adjustments” in this discussion due to its immaterial impact on current period
        financial results, but is presented separately in segment information provided
        in Note 13 to the consolidated financial statements. Net income (loss) by
        major business segment was as follows:
 
 **Three
                  Months Ended****March
                  31,**
              
              **Increase****2006**
              
              **2005**
              
              **(Decrease)****Net
                  Income (Loss)**
              
              ***(In
                  millions, except per share data)*****By
                  Business Segment**Regulated
                  services
              
              $
              211
              
              $
              236
              
              $
              (25
              )Power
                  supply
                  management services
              
              
              40
              
              
              (46
              )
              
              86Other
                  and
                  reconciling adjustments*
              
              
              (30
              )
              
              (30
              )
              
              -Total
              
              $
              221
              
              $
              160
              
              $
              61**Basic
                  Earnings Per Share:**Income
                  before
                  discontinued operations
              
              $
              0.67
              
              $
              0.43
              
              $
              0.24Discontinued
                  operations
              
              
              -
              
              
              0.06
              
              
              (0.06
              )Net
                  Income
              
              $
              0.67
              
              $
              0.49
              
              $
              0.18**Diluted
                  Earnings Per Share:**Income
                  before
                  discontinued operations
              
              $
              0.67
              
              $
              0.42
              
              $
              0.25Discontinued
                  operations
              
              
              -
              
              
              0.06
              
              
              (0.06
              )Net
                  Income
              
              $
              0.67
              
              $
              0.48
              
              $
              0.19
 
 *
              Represents
                  other operating segments and reconciling items including interest
                  expense
                  on holding company debt and corporate support services
                revenues
                  and
                  expenses.
  31
  Net income in the first quarter of 2005 included after-tax earnings from
        discontinued operations of $19 million ($0.06 per basic and diluted share)
        resulting from FirstEnergy’s disposition of non-core assets and operations. In
        the first quarter of 2005, discontinued operations included $17 million
        from net gains on sales and $2 million from operations.
 
 In the first quarter of 2005, earnings were increased by $0.02 per share
        from
        the combined impact of $0.07 per share of gains from the sale of non-core
        assets, offset by $0.04 per share of expense associated with the W. H. Sammis
        Plant New Source Review settlement and $0.01 per share of expense related
        to the
        fine by the Nuclear Regulatory Commission regarding the Davis-Besse Nuclear
        Power Station.
 
 Financial results for FirstEnergy's major business segments in the first
        quarter
        of 2006 and 2005 were as follows:
 
 **Power****Supply**
              
              **Other
                  and****Regulated**
              
              **Management**
              
              **Reconciling**
              
              **FirstEnergy****First
                  Quarter 2006 Financial Results**
              
              **Services**
              
              **Services**
              
              **Adjustments**
              
              **Consolidated*****(In
                  millions)***Revenues:ExternalElectric
              
              $
              935
              
              $
              1,576
              
              $
              -
              
              $
              2,511Other
              
              
              148
              
              
              43
              
              
              143
              
              
              334Internal
              
              
              -
              
              
              -
              
              
              -
              
              
              -Total
                  Revenues
              
              
              1,083
              
              
              1,619
              
              
              143
              
              
              2,845Expenses:Fuel
                  and
                  purchased power
              
              
              -
              
              
              976
              
              
              -
              
              
              976Other
                  operating expenses
              
              
              298
              
              
              451
              
              
              144
              
              
              893Provision
                  for
                  depreciation
              
              
              96
              
              
              46
              
              
              6
              
              
              148Amortization
                  of regulatory assets
              
              
              222
              
              
              -
              
              
              -
              
              
              222Deferral
                  of
                  new regulatory assets
              
              
              (59
              )
              
              -
              
              
              -
              
              
              (59
              )General
                  taxes
              
              
              140
              
              
              45
              
              
              8
              
              
              193Total
                  Expenses
              
              
              697
              
              
              1,518
              
              
              158
              
              
              2,373Operating
                  Income (Loss)
              
              
              386
              
              
              101
              
              
              (15
              )
              
              472Other
                  Income
                  (Expense):Investment
                  income
              
              
              62
              
              
              15
              
              
              (34
              )
              
              43Interest
                  expense
              
              
              (94
              )
              
              (53
              )
              
              (18
              )
              
              (165
              )Capitalized
                  interest
              
              
              3
              
              
              4
              
              
              -
              
              
              7Subsidiaries'
                  preferred stock dividends
              
              
              (2
              )
              
              -
              
              
              -
              
              
              (2
              )Total
                  Other
                  Income (Expense)
              
              
              (31
              )
              
              (34
              )
              
              (52
              )
              
              (117
              )Income
                  taxes
                  (benefit)
              
              
              144
              
              
              27
              
              
              (37
              )
              
              134Income
                  before
                  discontinued operations
              
              
              211
              
              
              40
              
              
              (30
              )
              
              221Discontinued
                  operations
              
              
              -
              
              
              -
              
              
              -
              
              
              -Net
                  Income
                  (Loss)
              
              $
              211
              
              $
              40
              
              $
              (30
              )
              $
              221
 
  32
  
 **Power****Supply**
              
              **Other
                  and****Regulated**
              
              **Management**
              
              **Reconciling**
              
              **FirstEnergy****First
                  Quarter 2005 Financial Results**
              
              **Services**
              
              **Services**
              
              **Adjustments**
              
              **Consolidated*****(In
                  millions)***Revenues:ExternalElectric
              
              $
              1,082
              
              $
              1,355
              
              $
              -
              
              $
              2,437Other
              
              
              134
              
              
              22
              
              
              157
              
              
              313Internal
              
              
              78
              
              
              -
              
              
              (78
              )
              
              -Total
                  Revenues
              
              
              1,294
              
              
              1,377
              
              
              79
              
              
              2,750Expenses:Fuel
                  and
                  purchased power
              
              
              -
              
              
              895
              
              
              -
              
              
              895Other
                  operating expenses
              
              
              324
              
              
              503
              
              
              57
              
              
              884Provision
                  for
                  depreciation
              
              
              123
              
              
              13
              
              
              7
              
              
              143Amortization
                  of regulatory assets
              
              
              311
              
              
              -
              
              
              -
              
              
              311Deferral
                  of
                  new regulatory assets
              
              
              (60
              )
              
              -
              
              
              -
              
              
              (60
              )General
                  taxes
              
              
              146
              
              
              32
              
              
              7
              
              
              185Total
                  Expenses
              
              
              844
              
              
              1,443
              
              
              71
              
              
              2,358Operating
                  Income (Loss)
              
              
              450
              
              
              (66
              )
              
              8
              
              
              392Other
                  Income
                  (Expense):Investment
                  income
              
              
              41
              
              
              -
              
              
              -
              
              
              41Interest
                  expense
              
              
              (94
              )
              
              (7
              )
              
              (63
              )
              
              (164
              )Capitalized
                  interest
              
              
              3
              
              
              (3
              )
              
              -
              
              
              -Subsidiaries'
                  preferred stock dividends
              
              
              (7
              )
              
              -
              
              
              -
              
              
              (7
              )Total
                  Other
                  Income (Expense)
              
              
              (57
              )
              
              (10
              )
              
              (63
              )
              
              (130
              )Income
                  taxes
                  (benefit)
              
              
              157
              
              
              (30
              )
              
              (6
              )
              
              121Income
                  before
                  discontinued operations
              
              
              236
              
              
              (46
              )
              
              (49
              )
              
              141Discontinued
                  operations
              
              
              -
              
              
              -
              
              
              19
              
              
              19Net
                  Income
                  (Loss)
              
              $
              236
              
              $
              (46
              )
              $
              (30
              )
              $
              160
 
 **Power****Change
                  Between First Quarter 2006 and**
              
              
              
              **Supply**
              
              **Other
                  and****First
                  Quarter 2005 Financial Results**
              
              **Regulated**
              
              **Management**
              
              **Reconciling**
              
              **FirstEnergy****Increase
                  (Decrease)**
              
              **Services**
              
              **Services**
              
              **Adjustments**
              
              **Consolidated*****(In
                  millions)***Revenues:ExternalElectric
              
              $
              (147
              )
              $
              221
              
              $
              -
              
              $
              74Other
              
              
              14
              
              
              21
              
              
              (14
              )
              
              21Internal
              
              
              (78
              )
              
              -
              
              
              78
              
              
              -Total
                  Revenues
              
              
              (211
              )
              
              242
              
              
              64
              
              
              95Expenses:Fuel
                  and
                  purchased power
              
              
              -
              
              
              81
              
              
              -
              
              
              81Other
                  operating expenses
              
              
              (26
              )
              
              (52
              )
              
              87
              
              
              9Provision
                  for
                  depreciation
              
              
              (27
              )
              
              33
              
              
              (1
              )
              
              5Amortization
                  of regulatory assets
              
              
              (89
              )
              
              -
              
              
              -
              
              
              (89
              )Deferral
                  of
                  new regulatory assets
              
              
              1
              
              
              -
              
              
              -
              
              
              1General
                  taxes
              
              
              (6
              )
              
              13
              
              
              1
              
              
              8Total
                  Expenses
              
              
              (147
              )
              
              75
              
              
              87
              
              
              15Operating
                  Income
              
              
              (64
              )
              
              167
              
              
              (23
              )
              
              80Other
                  Income
                  (Expense):Investment
                  income
              
              
              21
              
              
              15
              
              
              (34
              )
              
              2Interest
                  expense
              
              
              -
              
              
              (46
              )
              
              45
              
              
              (1
              )Capitalized
                  interest
              
              
              -
              
              
              7
              
              
              -
              
              
              7Subsidiaries'
                  preferred stock dividends
              
              
              5
              
              
              -
              
              
              -
              
              
              5Total
                  Other
                  Income (Expense)
              
              
              26
              
              
              (24
              )
              
              11
              
              
              13Income
                  taxes
              
              
              (13
              )
              
              57
              
              
              (31
              )
              
              13Income
                  before
                  discontinued operations
              
              
              (25
              )
              
              86
              
              
              19
              
              
              80Discontinued
                  operations
              
              
              -
              
              
              -
              
              
              (19
              )
              
              (19
              )Net
                  Income
              
              $
              (25
              )
              $
              86
              
              $
              -
              
              $
              61
 
  33
 
 ***Regulated
        Services - First Quarter 2006 Compared to First Quarter
        2005***
  Net income decreased $25 million (or 10.6%) to $211 million in the first
        quarter
        of 2006 compared to $236 million in the first quarter of 2005, primarily
        due to decreased operating revenues partially offset by lower operating expenses
        and taxes.
 
 *Revenues
        -*
 
 The decrease in total revenues resulted from the following sources:
 
 **Three
                  Months Ended****March
                  31,**
              
              **Increase****Revenues
                  By Type of Service**
              
              **2006**
              
              **2005**
              
              **(Decrease)*****(In
                  millions)***Distribution
                  services
              
              $
              935
              
              $
              1,082
              
              $
              (147
              )Transmission
                  services
              
              
              94
              
              
              92
              
              
              2Internal
                  revenues
              
              
              -
              
              
              78
              
              
              (78
              )Other
              
              
              54
              
              
              42
              
              
              12Total
                  Revenues
              
              $
              1,083
              
              $
              1,294
              
              $
              (211
              )
 
 Decreases in distribution deliveries by customer class are summarized in
        the
        following table:
 
 **Electric
                  Distribution Deliveries**Residential
              
              
              (2.6
              )%Commercial
              
              
              (2.1
              )%Industrial
              
              
              (2.9
              )%Total
                  Distribution Deliveries
              
              
              (2.6
              )%
  The completion of the Ohio Companies' generation transition cost recovery
        under
        their respective transition plans and Penn's transition plan in 2005 was
        the
        primary reason for lower distribution unit prices, which, in conjunction
        with
        lower KWH deliveries, resulted in lower distribution delivery revenues. The
        decreased deliveries to customers were primarily due to unseasonably mild
        weather during the first quarter of 2006. The following table summarizes
        major
        factors contributing to the $147 million decrease in distribution service
        revenues in the first quarter of 2006:
 
 **Sources
                  of Change in Distribution Revenues**
              
              **Decrease*****(In
                  millions)***Changes
                  in
                  customer usage
              
              $
              (5
              )Changes
                  in
                  prices:Rate
                  changes
              
              
              (124
              )Rate
                  mix &
                  other
              
              
              (18
              )Net
                  Decrease
                  in Distribution Revenues
              
              $
              (147
              )
  The decrease in internal revenues reflected the effect of the generation
        asset
        transfers discussed above. The 2005 generation assets lease revenue from
        affiliates ceased as a result of the transfers. Other revenues increased
        $14 million due in part to higher payments received under a contract
        provision associated with the prior sale of TMI. Under the contract, additional
        payments are received if subsequent energy prices rise above specified levels.
        These payments are passed along to JCP&L, Met-Ed and Penelec customers,
        resulting in no net earnings effect. Other revenues were also impacted by
        an
        increase in customer late payment charges.
 
 *Expenses-*
 
 The decrease in revenues discussed above was partially offset by the following
        decreases in total expenses:
 
 ·
              Other
                  operating expenses were $26 million lower in 2006 due in part to
                  the
                  following factors:
  1) The
        absence in 2006 of expenses for ancillary service refunds to third party
        suppliers of $7 million in 2005 due to the RCP, which provides that
        alternate
 suppliers of ancillary services now bill customers directly for those
          services;
 
 2)
              The
                  absence in
                  2006 of receivables factoring discount expenses of approximately
                  $5 million incurred in 2005;
                  and
 
 3) A
        $4
        million decrease in employee and contractor costs.
  34
  
 ·
              Lower
                  depreciation expense of $27 million that resulted from the impact
                  of the
                  generation asset transfers.
 
 ·
              Reduced
                  amortization of regulatory assets of $89 million principally due
                  to the
                  completion of Ohio generation transition cost recovery and Penn's
                  transition plan in 2005; and
 
 ·
              General
                  taxes
                  decreased by $6 million primarily due to lower property taxes as
                  a result
                  of the generation asset transfers.
 
 *Other
        Income
        -*
 
 ·
              Higher
                  investment income reflects the impact of the generation asset transfers.
                  Interest income on the affiliated company notes receivable from
                  the power
                  supply management services segment in the first quarter of 2006
                  is
                  partially offset by the absence in 2006 of the majority of nuclear
                  decommissioning trust income which is now included in the power
                  supply
                  management services segment; and
 
 ·
              Subsidiaries'
                  preferred stock dividends decreased by $5 million in 2006 due to
                  redemption activity in 2005.
 
 ***Power
        Supply Management Services - First Quarter 2006 Compared to First Quarter
        2005***
  Net income for this segment was $40 million in the first quarter of 2006
        compared to a net loss of $46 million in the same period last year. An
        improvement in the gross generation margin was partially offset by higher
        depreciation, general taxes and interest expense resulting from the generation
        asset transfers.
 
 *Revenues
        -*
  Electric
        generation
        sales revenues increased $199 million in the first quarter of 2006 compared
        to
        the same period in 2005. This increase primarily resulted from a 6.6% increase
        in retail KWH sales and higher unit prices resulting from the 2006 rate
        stabilization and fuel recovery charges. Additional retail sales reduced
        energy
        available for sales to the wholesale market. The transmission revenues increase
        reflected new revenues under the MISO transmission rider of approximately
        $27
        million that began in the first quarter of 2006.
 
 An increase in reported segment revenues resulted from the following
        sources:
 
 **Three
                  Months Ended****March
                  31,**
              
              **Increase****Revenues
                  By Type of Service**
              
              **2006**
              
              **2005**
              
              **(Decrease)*****(In
                  millions)***Electric
                  Generation Sales:Retail
              
              $
              1,239
              
              $
              980
              
              $
              259Wholesale
              
              
              235
              
              
              295
              
              
              (60
              )Total
                  Electric
                  Generation Sales
              
              
              1,474
              
              
              1,275
              
              
              199Retail
                  Transmission Rider
              
              
              116
              
              
              80
              
              
              36Other
                  Transmission
              
              
              12
              
              
              10
              
              
              2Other
              
              
              17
              
              
              12
              
              
              5Total
                  Revenues
              
              $
              1,619
              
              $
              1,377
              
              $
              242
 
 The following table summarizes the price and volume factors contributing
        to
        changes in sales revenues from retail and wholesale customers:
 
 **Increase****Source
                  of Change in Electric Generation Sales**
              
              **(Decrease)*****(In
                  millions)***Retail:Effect of 6.6% increase in customer usage
              
              $
              65Change in prices
              
              
              194259Wholesale:Effect
                  of
                  15.7% decrease in KWH sales
              
              
              (46
              )Change
                  in
                  prices
              
              
              (14
              )(60
              )Net
                  Increase
                  in Electric Generation Sales
              
              $
              199
   35
  *Expenses
        -*
 
 Total operating expenses increased by $75 million. The increase was due to
        the following factors:
 
 ·
              Higher
                  fuel
                  and purchased power costs of $81 million, including increased fuel
                  costs of $49 million, of which, coal costs, contributed $41 million
                  as a result of increased generation output and higher coal prices
                  reflecting higher transportation costs. The increase in coal
                  transportation costs is primarily due to a change in the fuel mix
                  resulting from a greater use of western coal. Purchased power costs,
                  net
                  of the Ohio RCP fuel deferral of $21 million, increased $32 million
                  due to higher prices partially offset by lower volume. 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
              
              $
              32Change
                  due to
                  volume consumed
              
              
              1749Purchased
                  Power:Change
                  due to
                  increased unit costs
              
              
              77Change
                  due to
                  volume purchased
              
              
              (33
              )Decrease
                  in
                  NUG costs deferred
              
              
              953Ohio
                  RCP fuel
                  deferrals
              
              
              (21
              )Net
                  Increase
                  in Fuel and Purchased Power Costs
              
              $
              81
 
 ·
              Higher
                  transmission expenses of $30 million related to the transmission
                  revenues
                  discussed above;
 
 ·
              Increased
                  depreciation expenses of $33 million, which resulted principally
                  from the
                  generation asset transfers; and
 
 ·
              Higher
                  general
                  taxes of $13 million due to additional property taxes resulting
                  from the
                  generation asset transfers.
 
 Offsetting
        these
        higher costs were lower non-fuel operating expenses of $52 million, which
        reflect the absence in 2006 of generating asset lease rents of $78 million
        charged in 2005 due to the generation asset transfers. Also absent in 2006
        were:
        (1) the 2005 accrual of an $8.5 million civil penalty payable to the DOJ
        and
        $10 million for obligations to fund environmentally beneficial projects in
        connection with the Sammis Plant settlement; and (2) a $3.5 million penalty
        related to the Davis-Besse outage.
 
 *Other
        Income -*
  ·
                Investment
                    income in the first quarter of 2006 was higher by $15 million
                    over the
                    prior year period primarily due to nuclear decommissioning trust
                    investments   acquired through the generation asset transfers;
                    and·
                Interest
                    expense increased by $46 million, primarily due to the interest
                    expense in
                    2006 on associated company notes payable used in connection with
                    the
                    generation asset transfers. This increase was partially offset
                    by an
                    additional $7 million of capitalized
                    interest.
  Income
        Taxes *-* Income
        taxes
        increased as a result of higher taxable income.
  36
 
 ***Other
        -
        First Quarter 2006 Compared to First Quarter 2005***
 
 FirstEnergy’s financial results from other operating segments and reconciling
        items, including interest expense on holding company debt and corporate support
        services revenues and expenses, resulted in no change to FirstEnergy’s net
        income in the first quarter of 2006 compared to the same quarter of 2005.
        The
        effect of lower income taxes due to allocations among the business segments
        offset the effect of the absence of the results of the 2005 discontinued
        operations. The 2005 results reflected the effect of discontinued operations,
        which included an after-tax net gain of $17 million from discontinued
        operations (see Note 4). The following table summarizes the sources of income
        from discontinued operations for the three months ended March 31,
        2005:
 ***(In
                  millions)***Discontinued
                  Operations (Net of tax)Gain
                  on
                  sale:Natural gas business
              
              $
              5Elliot-Lewis, Spectrum and Power Piping
              
              
              12Reclassification
                  of operating income
              
              
              2Total
              
              $
              19
 
 **CAPITAL
        RESOURCES AND LIQUIDITY**
 
 During
        2006 and
        thereafter, FirstEnergy expects to meet its contractual obligations primarily
        with a combination of cash from operations and funds from the capital markets.
        Borrowing capacity under credit facilities is available to manage working
        capital requirements.
 
 ***Changes
        in Cash Position***
 
 FirstEnergy's
        primary source of cash required for continuing operations as a holding company
        is cash from the operations of its subsidiaries. FirstEnergy also has access
        to
        $2.0 billion of short-term financing under a revolving credit facility
        which expires in 2010, subject to short-term debt limitations under current
        regulatory approvals of $1.5 billion and to outstanding borrowings by
        subsidiaries of FirstEnergy that are also parties to such facility. In the
        first
        quarter of 2006, FirstEnergy received $148 million of cash dividends from
        its subsidiaries and paid $148 million in cash dividends to common
        shareholders. There are no material restrictions on the payment of cash
        dividends by FirstEnergy's subsidiaries.
 
 As
        of March 31,
        2006, FirstEnergy had $28 million of cash and cash equivalents compared
        with $64 million as of December 31, 2005. The major sources for
        changes in these balances are summarized below.
 
 **Cash
        Flows
        From Operating Activities**
  FirstEnergy's consolidated net cash from operating activities is provided
        primarily by its regulated services and power supply management services
        businesses (see Results of Operations above). Net cash provided from operating
        activities was $402 million in the first quarter of 2006 and
        $598 million in the first quarter of 2005, summarized as follows:
 
 **Three
                  Months Ended****March
                  31,****Operating
                  Cash Flows**
              
              **2006**
              
              **2005*****(In
                  millions)***Cash
                  earnings(1)
              
              $
              388
              
              $
              359Working
                  capital and other
              
              
              14
              
              
              239Net
                  cash
                  provided from operating activities
              
              $
              402
              
              $
              598
  (1)  
        Cash earnings
        is a Non-GAAP measure (see reconciliation below).
  37
  Cash earnings (in the table above) are not a measure of performance calculated
        in accordance with GAAP. FirstEnergy believes that cash earnings are 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****March
                  31,****Reconciliation
                  of Cash Earnings**
              
              **2006**
              
              **2005*****(In
                  millions)***Net
                  Income
                  (GAAP)
              
              $
              221
              
              $
              160Non-Cash
                  Charges (Credits):Provision
                  for
                  depreciation
              
              
              148
              
              
              143Amortization
                  of regulatory assets
              
              
              222
              
              
              311Deferral
                  of
                  new regulatory assets
              
              
              (59
              )
              
              (60
              )Nuclear
                  fuel
                  and lease amortization
              
              
              20
              
              
              19Deferred
                  purchased power and other costs
              
              
              (125
              )
              
              (118
              )Deferred
                  income taxes and investment tax credits
              
              
              6
              
              
              (14
              )Deferred
                  rents
                  and lease market valuation liability
              
              
              (38
              )
              
              (36
              )Accrued
                  compensation and retirement benefits
              
              
              (19
              )
              
              (26
              )Income
                  from
                  discontinued operations
              
              
              -
              
              
              (19
              )Other
                  non-cash
                  expenses
              
              
              12
              
              
              (1
              )Cash
                  Earnings
                  (Non-GAAP)
              
              $
              388
              
              $
              359
  Net cash provided from operating activities decreased by $196 million in
        the
        first quarter of 2006 compared to the first quarter of 2005 primarily due
        to a
        $225 million decrease in working capital, partially offset by a $29 million
        increase in cash earnings described under "Results of Operations." The working
        capital decrease primarily resulted from increased outflows of $175 million
        for
        payables and $59 million for materials and supplies which reflected increased
        generation costs as discussed above and fuel inventory replacement activity
        due
        to increased fossil fuel consumption and higher unit prices; and $108 million
        of
        cash collateral returned to suppliers. These decreases were partially
        offset by an increase in cash provided from the settlement of receivables
        balances of $135 million which reflects increased electric sales
        revenues.
 
 **Cash
        Flows
        From Financing Activities**
  In
        the first quarters of 2006 and 2005, net cash used for financing activities
        was
        $50 million and $359 million, respectively, primarily resulting from
        the redemptions of debt and preferred stock as shown below.
 
 **Three
                  Months Ended****March
                  31,****Securities
                  Issued or Redeemed**
              
              **2006**
              
              **2005*****(In
                  millions)****Redemptions*FMB
              
              $
              -
              
              $
              1Pollution
                  control notes
              
              
              54
              
              
              -Senior
                  secured
                  notes
              
              
              10
              
              
              20Long-term
                  revolving credit
              
              
              -
              
              
              215Preferred
                  stock
              
              
              30
              
              
              98$
              94
              
              $
              334Short-term
                  Borrowings, Net
              
              $
              200
              
              $
              140
 
  38
 
 FirstEnergy had approximately $931 million of short-term indebtedness as
        of
        March 31, 2006 compared to approximately $731 million as of
        December 31, 2005. This increase was due primarily to increased capital
        spending including the costs associated with the Davis-Besse and Beaver Valley
        Unit 1 refueling outages during the first quarter of 2006 and lower customer
        cash receipts. Available bank borrowing capability as of March 31, 2006
        included the following:
 
 **Borrowing
                  Capability*****(In
                  millions)***Short-term
                  credit facilities(1)
              
              $
              2,120Accounts
                  receivable financing facilities
              
              
              550Utilized
              
              
              (919
              )LOCs
              
              
              (116
              )Net
              
              $
              1,635(1)
                A $2 billion revolving credit facility that expires in 2010
                  is
                  available in various amounts to FirstEnergy and certain of its
                  subsidiaries. A $100 million revolving credit facility that expires
                  in
                  December 2006 and a $20 million uncommitted line of credit facility
                  that
                  expires in September 2006 are both available to FirstEnergy
                  only.
 
 As
        of March 31,
        2006, the Ohio Companies and Penn had the aggregate capability to issue
        approximately $1.3 billion of additional FMB on the basis of property
        additions and retired bonds under the terms of their respective mortgage
        indentures. The issuance of FMB by OE and CEI are also subject to provisions
        of
        their senior note indentures generally limiting the incurrence of additional
        secured debt, subject to certain exceptions that would permit, among other
        things, the issuance of secured debt (including FMB) (i) supporting pollution
        control notes or similar obligations, or (ii) as an extension, renewal or
        replacement of previously outstanding secured debt. In addition, these
        provisions would permit OE and CEI to incur additional secured debt not
        otherwise permitted by a specified exception of up to $644 million and
        $576 million, respectively, as of March 31, 2006. Under the provisions
        of its senior note indenture, JCP&L may issue additional FMB only as
        collateral for senior notes. As of March 31, 2006, JCP&L had the
        capability to issue $625 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 $6 billion of preferred stock
        (assuming no additional debt was issued) as of March 31, 2006. CEI, Met-Ed
        and Penelec do not have similar restrictions and could issue up to the number
        of
        preferred stock shares authorized under their respective charters.
 
 As
        of March 31,
        2006, approximately $1 billion of capacity remained unused under an
        existing shelf registration statement, filed by FirstEnergy with the SEC
        in
        2003, to support future securities issuances. The shelf registration provides
        the flexibility to issue and sell various types of securities, including
        common
        stock, debt securities, and share purchase contracts and related share purchase
        units. As of April 26, 2006, a shelf registration statement filed by OE became
        effective and provides, together with previously effective OE registration
        statements, $1 billion of capacity to support future issuances of debt
        securities by OE.
 
 FirstEnergy's
        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 mature on the earlier of 364 days from the date of borrowing or the
        commitment expiration date, June 16, 2010.
  39
 
 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
              
              
              43**CEI**
              
              
              250
              
              
              500**TE**
              
              
              250
              
              
              500**JCP&L**
              
              
              425
              
              
              412**Met-Ed**
              
              
              250
              
              
              300**Penelec**
              
              
              250
              
              
              300**FES**
              
              
              -2
              
              
              n/a**ATSI**
              
              
              -2
              
              
              26
 
 (1)
              As
                  of March
                  31, 2006.
 (2)
              Borrowing
                  sub-limits for FES and ATSI may be increased to up to $250 million
                  and
                  $100
                  million, respectively, by delivering notice to the administrative
                  agent
                  that either (i)such
                  borrower
                  has senior unsecured debt ratings of at least BBB- by S&P and Baa3 byMoody’s
                  or
                  (ii) FirstEnergy has guaranteed the obligations of such borrower
                  under the
                  facility.
  The revolving credit facility, combined with an aggregate $550 million
        ($292 million unused as of March 31, 2006) 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 LOCs expiring up to
        one
        year from the date of issuance. The stated amount of outstanding LOCs will
        count
        against total commitments available under the facility and against the
        applicable borrower’s borrowing sub-limit. Total unused borrowing capability
        under existing credit facilities and accounts receivable financing facilities
        was $1.6 billion as of March 31, 2006.
 
 The
        revolving credit
        facility contains financial covenants requiring each borrower to maintain
        a
        consolidated debt to total capitalization ratio of no more than 65%, measured
        at
        the end of each fiscal quarter.
 
 As
        of March 31,
        2006, FirstEnergy and its subsidiaries' debt to total capitalization ratios
        (as
        defined under the revolving credit facility) were as follows:
 
 **Borrower****FirstEnergy**
              
              
              54
              %**OE**
              
              
              33
              %**Penn**
              
              
              35
              %**CEI**
              
              
              52
              %**TE**
              
              
              31
              %**JCP&L**
              
              
              27
              %**Met-Ed**
              
              
              39
              %**Penelec**
              
              
              36
              %
 
 The
        revolving credit
        facility does not contain provisions that either restrict the ability to
        borrow
        or accelerate repayment of outstanding advances as a result of any change
        in
        credit ratings. Pricing is defined in “pricing grids”, whereby the cost of funds
        borrowed under the facility is related to the credit ratings of the company
        borrowing the funds.
 
 FirstEnergy's
        regulated companies also have the ability to borrow from each other and the
        holding company to meet their short-term working capital requirements. A
        similar
        but separate arrangement exists among FirstEnergy's unregulated companies.
        FESC
        administers these two money pools and tracks surplus funds of FirstEnergy
        and
        the respective regulated and unregulated subsidiaries, as well as proceeds
        available from bank borrowings. Companies receiving a loan under the money
        pool
        agreements must repay the principal amount of the loan, together with
        accrued interest, within 364 days of borrowing the funds. The rate of interest is
        the
        same for each company receiving a loan from their respective pool and is
        based
        on the average cost of funds available through the pool. The average interest
        rate for borrowings in the first quarter of 2006 was approximately 4.58%
        for
        both the regulated companies’ money pool and the unregulated companies' money
        pool.
  40
 
 FirstEnergy’s
        access
        to capital markets and costs of financing are influenced by the ratings of
        its
        securities. The following table displays FirstEnergy’s and the Companies'
        securities ratings as of March 31, 2006. The ratings outlook from S&P
        on all securities is stable. The ratings outlook from Moody's and Fitch on
        all
        securities is positive.
 
 **Issuer**
              
              **Securities**
              
              **S&P**
              
              **Moody’s**
              
              **Fitch****FirstEnergy**
              
              Senior
                  unsecured
              
              BBB-
              
              Baa3
              
              BBB-**OE**
              
              Senior
                  unsecured
              
              BBB-
              
              Baa2
              
              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 January 20, 2006, TE redeemed all 1.2 million of its outstanding
        shares of Adjustable Rate Series B preferred stock at $25.00 per share, plus
        accrued dividends to the date of redemption.
 
 On
        April 3, 2006,
        NGC issued pollution control revenue refunding bonds ($60 million at 3.07%
        and
        $46.5 million at 3.25%). These bonds were used to redeem the following
        Companies' pollution control notes (OE - $60 million at 7.05%, CEI - $27.7
        million at 3.32%, TE - $18.8 million at 3.32%) on April 3, 2006. Also on
        April 3, 2006, FGCO issued pollution control revenue refunding bonds ($90.1
        million at 3.03% and $56.6 million at 3.10%) which were used to redeem the
        following Companies' pollution control notes (OE - $14.8 million at 5.45%,
        Penn
        - $6.95 million at 5.45%, TE - $34.85 million at 3.18%, CEI - $47.5
        million at 3.22%, $39.8 million at 3.20% and $2.8 million at 3.15%) in April
        and
        May 2006. These refinancings were undertaken in furtherance of FirstEnergy's
        intra-system generation asset transfers (see Note 14). The proceeds from
        NGC's
        and FGCO's refinancing issuances were used to repay a portion of their
        associated company notes payable to OE, Penn, CEI, and TE, who then redeemed
        their respective debt.
 
 FirstEnergy
        will
        consider a common stock repurchase program later in 2006 after satisfactorily
        finalizing its environmental compliance plans for its fossil
        plants.
  41
 
 **Cash
        Flows
        From Investing Activities**
  Net cash flows used in investing activities resulted principally from property
        additions. Regulated services expenditures for property additions primarily
        include expenditures supporting the distribution of electricity. Capital
        expenditures by the power supply management services segment are principally
        generation-related. The following table summarizes investments for the first
        quarter of 2006 and 2005 by segment:
 
 **Summary
                  of Cash Flows**
              
              **Property****Used
                  for Investing Activities**
              
              **Additions**
              
              **Investments**
              
              **Other**
              
              **Total****Sources
                  (Uses)**
              
              ***(In
                  millions)*****Three
                  Months Ended March 31, 2006**Regulated
                  services
              
              $
              (195
              )
              $
              58
              
              $
              (7
              )
              $
              (144
              )Power
                  supply
                  management services
              
              
              (244
              )
              
              (34
              )
              
              -
              
              
              (278
              )Other
              
              
              (1
              )
              
              16
              
              
              (5
              )
              
              10Inter-Segment
                  reconciling items
              
              
              (7
              )
              
              30
              
              
              1
              
              
              24Total
              
              $
              (447
              )
              $
              70
              
              $
              (11
              )
              $
              (388
              )**Three
                  Months Ended March 31, 2005**Regulated
                  services
              
              $
              (141
              )
              $
              21
              
              $
              3
              
              $
              (117
              )Power
                  supply
                  management services
              
              
              (81
              )
              
              14
              
              
              -
              
              
              (67
              )Other
              
              
              (3
              )
              
              1
              
              
              (13
              )
              
              (15
              )Inter-Segment
                  reconciling items
              
              
              (4
              )
              
              (8
              )
              
              -
              
              
              (12
              )Total
              
              $
              (229
              )
              $
              28
              
              $
              (10
              )
              $
              (211
              )
  Net
        cash used for
        investing activities in the first quarter of 2006 increased by $177 million
        compared to the first quarter of 2005. The increase was principally due to
        a
        $218 million increase in property additions which reflects the replacement
        of
        the steam generators and reactor head at Beaver Valley Unit 1 and the
        distribution system Accelerated Reliability Improvement Program. The increase
        in
        property additions was partially offset by a $22 million decrease in net
        nuclear decommissioning trust activities due to completion of the Ohio
        Companies' and Penn's transition cost recovery for decommissioning at the
        end of
        2005.
 
 During
        the remaining
        three quarters of 2006, capital requirements for property additions and capital
        leases are expected to be approximately $860 million. FirstEnergy and the
        Companies have additional requirements of approximately $1.3 billion for
        maturing long-term debt during the remainder of 2006. These cash requirements
        are expected to be satisfied from a combination of internal cash, funds raised
        in the long-term debt capital markets and short-term credit arrangements.
 
 FirstEnergy's
        capital spending for the period 2006-2010 is expected to be about
        $6.7 billion (excluding nuclear fuel), of which $1.1 billion applies
        to 2006. Investments for additional nuclear fuel during the 2006-2010 periods
        are estimated to be approximately $769 million, of which about
        $164 million applies to 2006. During the same period, FirstEnergy's nuclear
        fuel investments are expected to be reduced by approximately $574 million
        and $92 million, respectively, as the nuclear fuel is consumed.
 
 **GUARANTEES
        AND OTHER ASSURANCES**
 
 As
        part of normal
        business activities, FirstEnergy enters into various agreements on behalf
        of its
        subsidiaries to provide financial or performance assurances to third parties.
        These agreements include contract guarantees, surety bonds, and LOCs. Some
        of
        the guaranteed contracts contain collateral provisions that are contingent
        upon
        FirstEnergy's credit ratings.
  42
 
 As
        of March 31,
        2006, FirstEnergy's maximum exposure to potential future payments under
        outstanding guarantees and other assurances totaled approximately
        $3.3 billion, as summarized below:
 
 **Maximum****Guarantees
                  and Other Assurances**
              
              **Exposure*****(In
                  millions)***FirstEnergy
                  Guarantees of Subsidiaries:Energy
                  and
                  Energy-Related Contracts(1)
              
              $
              906Other(2)
              
              
              8841,790Surety
                  Bonds
              
              
              136LOC(3)(4)
              
              
              1,340Total
                  Guarantees and Other Assurances
              
              $
              3,266
 
 (1)
              Issued
                  for
                  open-ended terms, with a 10-day termination right by
                  FirstEnergy.
 (2)
              Issued
                  for
                  various terms.
 (3)
              Includes
                  $116
                  million issued for various terms under LOC capacity available under
                  FirstEnergy’s revolving credit agreement and $604 million outstanding in
                  support of pollution control revenue bonds issued with various
                  maturities.
 (4)
              Includes
                  approximately $194 million pledged in connection with the sale
                  and
                  leaseback of Beaver Valley Unit 2 by CEI and TE, $291 million pledged
                  in
                  connection with the sale and leaseback of Beaver Valley Unit 2
                  by OE and
                  $134 million pledged in connection with the sale and leaseback
                  of Perry
                  Unit 1 by OE.
 
 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 its
        subsidiaries directly involved in these energy and energy-related transactions
        or financings where the law might otherwise limit the counterparties' claims.
        If
        demands of a counterparty were to exceed the ability of a subsidiary to satisfy
        existing obligations, FirstEnergy's guarantee enables the counterparty's
        legal
        claim to be satisfied by FirstEnergy's other assets. The likelihood that
        such
        parental guarantees will increase amounts otherwise paid by FirstEnergy to
        meet
        its obligations incurred in connection with ongoing energy and energy-related
        contracts is remote.
 
 While
        these types of
        guarantees are normally parental commitments for the future payment of
        subsidiary obligations, subsequent to the occurrence of a credit rating
        downgrade or “material adverse event” the immediate posting of cash collateral
        or provision of an LOC may be required of the subsidiary. As of March 31,
        2006, FirstEnergy's maximum exposure under these collateral provisions was
        $456
        million.
 
 Most
        of
        FirstEnergy's surety bonds are backed by various indemnities common within
        the
        insurance industry. Surety bonds and related guarantees provide additional
        assurance to outside parties that contractual and statutory obligations will
        be
        met in a number of areas including construction contracts, environmental
        commitments and various retail transactions.
 
 FirstEnergy
        has
        guaranteed the obligations of the operators of the TEBSA project up to a
        maximum
        of $6 million (subject to escalation) under the project's operations and
        maintenance agreement. In connection with the sale of TEBSA in January 2004,
        the
        purchaser indemnified FirstEnergy against any loss under this guarantee.
        FirstEnergy has also provided an LOC ($36 million as of March 31,
        2006), which is renewable and declines yearly based upon the senior outstanding
        debt of TEBSA.
 
 **OFF-BALANCE
        SHEET ARRANGEMENTS**
 
 FirstEnergy
        has
        obligations that are not included on its Consolidated Balance Sheets related
        to
        the sale and leaseback arrangements involving Perry 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
        March 31, 2006.
 
 FirstEnergy
        has
        equity ownership interests in certain businesses that are accounted for using
        the equity method. There are no undisclosed material contingencies related
        to
        these investments. Certain guarantees that FirstEnergy does not expect to
        have a
        material current or future effect on its financial condition, liquidity or
        results of operations are disclosed under Guarantees and Other Assurances
        above.
  43
  
 **MARKET
        RISK
        INFORMATION**
 
 FirstEnergy
        uses
        various market risk sensitive instruments, including derivative contracts,
        primarily to manage the risk of price and interest rate fluctuations.
        FirstEnergy's Risk Policy Committee, comprised of members of senior management,
        provides general oversight to risk management activities throughout the Company.
 
 **Commodity
        Price Risk**
 
 FirstEnergy
        is
        exposed to financial and market risks resulting from the fluctuation of interest
        rates and commodity prices primarily due to fluctuations in electricity,
        energy
        transmission, natural gas, coal, nuclear fuel and emission allowance prices.
        To
        manage the volatility relating to these exposures, FirstEnergy uses a variety
        of
        non-derivative and derivative instruments, including forward contracts, options,
        futures contracts and swaps. The derivatives are used principally for hedging
        purposes. Derivatives that fall within the scope of SFAS 133 must be
        recorded at their fair value and marked to market. The majority of FirstEnergy's
        derivative hedging contracts qualify for the normal purchase and normal sale
        exception under SFAS 133 and are therefore excluded from the table below.
        Contracts that are not exempt from such treatment include power purchase
        agreements with NUG entities that were structured pursuant to the Public
        Utility
        Regulatory Policies Act of 1978. These non-trading contracts are adjusted
        to
        fair value at the end of each quarter, with a corresponding regulatory asset
        recognized for above-market costs. The change in the fair value of commodity
        derivative contracts related to energy production during the first quarter
        of
        2006 is summarized in the following table:
 
 **Increase
                  (Decrease) in the Fair Value of Commodity Derivative
                  Contracts**
              
              **Non-Hedge**
              
              **Hedge**
              
              **Total*****(In
                  millions)*****Change
                  in the Fair Value of Commodity Derivative
                  Contracts:**Outstanding
                  net liability as of January 1, 2006
              
              $
              (1,170
              )
              $
              (3
              )
              $
              (1,173
              )New
                  contract
                  value when entered
              
              
              -
              
              
              -
              
              
              -Additions/change
                  in value of existing contracts
              
              
              122
              
              
              (7
              )
              
              115Change
                  in
                  techniques/assumptions
              
              
              -
              
              
              -
              
              
              -Settled
                  contracts
              
              
              (81
              )
              
              5
              
              
              (76
              )Outstanding
                  net liability as of March 31, 2006(1)
              
              $
              (1,129
              )
              $
              (5
              )
              $
              (1,134
              )**Non-commodity
                  Net Assets as of March 31, 2006**:Interest
                  Rate
                  Swaps(2)
              
              
              -
              
              
              (16
              )
              
              (16
              )**Net
                  Liabilities - Derivatives Contracts as of March 31,
                  2006**
              
              $
              (1,129
              )
              $
              (21
              )
              $
              (1,150
              )**Impact
                  of Changes in Commodity Derivative Contracts:****(3)**Income
                  Statement Effects (Pre-Tax)
              
              $
              (2
              )
              $
              -
              
              $
              (2
              )Balance
                  Sheet
                  Effects:Other
                  Comprehensive Income (Pre-Tax)
              
              $
              -
              
              $
              (2
              )
              $
              (2
              )Regulatory
                  Asset (net)
              
              $
              (43
              )
              $
              -
              
              $
              (43
              )
 
 (1)  Includes
        $1,140
        million in non-hedge commodity derivative contracts (primarily with NUGs),
        which
        are offset by a regulatory asset.
 (2)  Interest
        rate swaps
        are treated as cash flow or fair value hedges (see Interest Rate Swap Agreements
        below).
 (3)  Represents
        the
        change in value of existing contracts, settled contracts and changes in
        techniques/assumptions.
 
 Derivatives are included on the Consolidated Balance Sheet as of March 31,
        2006
        as follows:
 
 **Balance
                  Sheet Classification**
              
              **Non-Hedge**
              
              **Hedge**
              
              **Total*****(In
                  millions)*****Current-**Other
                  assets
              
              $
              5
              
              $
              12
              
              $
              17Other
                  liabilities
              
              
              (9
              )
              
              (15
              )
              
              (24
              )**Non-Current-**Other
                  deferred
                  charges
              
              
              46
              
              
              30
              
              
              76Other
                  noncurrent liabilities
              
              
              (1,171
              )
              
              (48
              )
              
              (1,219
              )Net
                  assets
                  (liabilities)
              
              $
              (1,129
              )
              $
              (21
              )
              $
              (1,150
              )
 
  44
 
 The valuation of derivative contracts is based on observable market information
        to the extent that such information is available. In cases where such
        information is not available, FirstEnergy relies on model-based information.
        The
        model provides estimates of future regional prices for electricity and an
        estimate of related price volatility. FirstEnergy uses these results to develop
        estimates of fair value for financial reporting purposes and for internal
        management decision making. Sources of information for the valuation of
        commodity derivative contracts by year are summarized in the following table:
 
 **Source
                  of Information****-
                  Fair
                  Value by Contract Year**
              
              **2006**(1)
              
              **2007**
              
              **2008**
              
              **2009**
              
              **2010**
              
              **Thereafter**
              
              **Total*****(In
                  millions)***Prices
                  actively quoted(2)
              
              $
              (2
              )
              $
              (2
              )
              $
              -
              
              $
              -
              
              $
              -
              
              $
              -
              
              $
              (4
              )Other
                  external
                  sources(3)
              
              
              (281
              )
              
              (284
              )
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              (565
              )Prices
                  based
                  on models
              
              
              -
              
              
              -
              
              
              (246
              )
              
              (166
              )
              
              (137
              )
              
              (16
              )
              
              (565
              )**Total****(4)**
              
              $
              (283
              )
              $
              (286
              )
              $
              (246
              )
              $
              (166
              )
              $
              (137
              )
              $
              (16
              )
              $
              (1,134
              )
 
 (1)  For
        the last three
        quarters of 2006.
 (2)  Exchange
        traded.
 (3)  Broker
        quote
        sheets.
 (4)
              Includes
                  $1,140 million in non-hedge commodity derivative contracts (primarily
                  with
                  NUGs), which are offset by a regulatory
                  asset.
  FirstEnergy
        performs
        sensitivity analyses to estimate its exposure to the market risk of its
        commodity positions. A hypothetical 10% adverse shift (an increase or decrease
        depending on the derivative position) in quoted market prices in the near
        term
        on its derivative instruments would not have had a material effect on its
        consolidated financial position (assets, liabilities and equity) or cash
        flows
        as of March 31, 2006. Based on derivative contracts held as of
        March 31, 2006, an adverse 10% change in commodity prices would decrease
        net income by approximately $5 million during the next 12 months.
 
 ***Interest
        Rate Swap Agreements- Fair Value Hedges***
 
 FirstEnergy
        utilizes
        fixed-for-floating interest rate swap agreements as part of its ongoing effort
        to manage the interest rate risk associated with its debt portfolio. These
        derivatives are treated as fair value hedges of fixed-rate, long-term debt
        issues - 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 first quarter of 2006, FirstEnergy unwound swaps
        with a
        total notional amount of $350 million for which FirstEnergy paid
        $1 million in cash. The loss will be recognized over the remaining maturity
        of each respective hedged security as increased interest expense. As of
        March 31, 2006, the debt underlying the $750 million outstanding
        notional amount of interest rate swaps had a weighted average fixed interest
        rate of 5.74%, which the swaps have converted to a current weighted average
        variable rate of 6.24%.
 
 **March
                  31, 2006**
              
              **December
                  31, 2005****Notional**
              
              **Maturity**
              
              **Fair**
              
              **Notional**
              
              **Maturity**
              
              **Fair****Interest
                  Rate Swaps**
              
              **Amount**
              
              **Date**
              
              **Value**
              
              **Amount**
              
              **Date**
              
              **Value*****(In
                  millions)***(Fair
                  value
                  hedges)
              
              $
              100
              
              
              2008
              
              $
              (4
              )
              $
              100
              
              
              2008
              
              $
              (3
              )50
              
              
              2010
              
              
              (1
              )
              
              50
              
              
              2010
              
              
              --
              
              
              2011
              
              
              -
              
              
              50
              
              
              2011
              
              
              -300
              
              
              2013
              
              
              (12
              )
              
              450
              
              
              2013
              
              
              (4
              )150
              
              
              2015
              
              
              (13
              )
              
              150
              
              
              2015
              
              
              (9
              )-
              
              
              2016
              
              
              -
              
              
              150
              
              
              2016
              
              
              -50
              
              
              2025
              
              
              (2
              )
              
              50
              
              
              2025
              
              
              (1
              )100
              
              
              2031
              
              
              (8
              )
              
              100
              
              
              2031
              
              
              (5
              )$
              750
              
              
              
              
              $
              (40
              )
              $
              1,100
              
              
              
              
              $
              (22
              )
 
 ***Forward
        Starting Swap Agreements - Cash Flow Hedges***
 
 FirstEnergy
        utilizes
        forward starting swap agreements (forward swaps) in order to hedge a portion
        of
        the consolidated interest rate risk associated with the anticipated future
        issuances of fixed-rate, long-term debt securities for one or more of its
        consolidated subsidiaries in 2006 through 2008. These derivatives are treated
        as
        cash flow hedges, protecting against the risk of changes in future interest
        payments resulting from changes in benchmark U.S. Treasury rates between
        the
        date of hedge inception and the date of the debt issuance. During the first
        quarter of 2006, FirstEnergy entered into forward swaps with a total notional
        amount of $525 million and terminated forward swaps with a total notional
        amount
        of $500 million from which FirstEnergy received $16 million in cash. The
        gain
        associated with the ineffective portion of the terminated hedges ($5 million)
        was recognized in earnings in the first quarter of 2006, with the remainder
        to
        be recognized over the terms of the respective forward swaps. As of
        March 31, 2006, FirstEnergy had outstanding forward swaps with an aggregate
        notional amount of $1 billion and an aggregate fair value of
        $25 million.
   45
 
 **March
                  31, 2006**
              
              **December
                  31, 2005****Notional**
              
              **Maturity**
              
              **Fair**
              
              **Notional**
              
              **Maturity**
              
              **Fair****Forward
                  Starting Swaps**
              
              **Amount**
              
              **Date**
              
              **Value**
              
              **Amount**
              
              **Date**
              
              **Value*****(In
                  millions)***(Cash
                  flow
                  hedges)
              
              $
              25
              
              
              2015
              
              $
              1
              
              $
              25
              
              
              2015
              
              $
              -250
              
              
              2016
              
              
              8
              
              
              600
              
              
              2016
              
              
              250
              
              
              2017
              
              
              1
              
              
              25
              
              
              2017
              
              
              -125
              
              
              2018
              
              
              4
              
              
              275
              
              
              2018
              
              
              150
              
              
              2020
              
              
              2
              
              
              50
              
              
              2020
              
              
              -500
              
              
              2036
              
              
              9
              
              
              -
              
              
              2036
              
              
              -$
              1,000
              
              
              
              
              $
              25
              
              $
              975
              
              
              
              
              $
              3
 
 ***Equity
        Price Risk***
 
 Included in nuclear decommissioning trusts are marketable equity securities
        carried at their market value of approximately $1.1 billion as of March 31,
        2006 and December 31, 2005. A hypothetical 10% decrease in prices quoted by
        stock exchanges would result in a $113 million reduction in fair value as
        of March 31, 2006.
 
 **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 March 31, 2006, the largest credit concentration with one
        party (currently rated investment grade) represented 7.1% of FirstEnergy's
        total
        credit risk. Within FirstEnergy's unregulated energy subsidiaries, 99% of
        credit
        exposures, net of collateral and reserves, were with investment-grade
        counterparties as of March 31, 2006.
 
 **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;·
                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.
 46
  The Companies and ATSI recognize, as regulatory assets, costs which the FERC,
        PUCO, PPUC and NJBPU have authorized for recovery from customers in future
        periods or for which authorization is probable. Without the probability of
        such
        authorization, costs currently recorded as regulatory assets would have been
        charged to income as incurred. Regulatory assets that do not earn a current
        return totaled approximately $237 million as of March 31, 2006. The
        following table discloses the regulatory assets by company and by
        source:
 
 **March
                  31,**
              
              **December
                  31,**
              
              **Increase****Regulatory
                  Assets***
              
              **2006**
              
              **2005**
              
              **(Decrease)*****(In
                  millions)***OE
              
              $
              757
              
              $
              775
              
              $
              (18
              )CEI
              
              
              858
              
              
              862
              
              
              (4
              )TE
              
              
              276
              
              
              287
              
              
              (11
              )JCP&L
              
              
              2,168
              
              
              2,227
              
              
              (59
              )Met-Ed
              
              
              308
              
              
              310
              
              
              (2
              )ATSI
              
              
              29
              
              
              25
              
              
              4Total
              
              $
              4,396
              
              $
              4,486
              
              $
              (90
              )
 
 *
              Penn
                  had net
                  regulatory liabilities of approximately $64 million and $59 million
                  as of
                  March 31, 2006 and December 31, 2005. Penelec had net regulatory
                  liabilities of approximately $156 million and $163 million as of
                  March 31, 2006 and December 31, 2005. These net regulatory
                  liabilities are included in Other Noncurrent Liabilities on the
                  Consolidated Balance Sheets.
 
 Regulatory
        assets by
        source are as follows:
 
 **March
                  31,**
              
              **December
                  31,**
              
              **Increase****Regulatory
                  Assets By Source**
              
              **2006**
              
              **2005**
              
              **(Decrease)*****(In
                  millions)***Regulatory
                  transition costs
              
              $
              3,470
              
              $
              3,576
              
              $
              (106
              )Customer
                  shopping incentives
              
              
              662
              
              
              884
              
              
              (222
              )Customer
                  receivables for future income taxes
              
              
              215
              
              
              217
              
              
              (2
              )Societal
                  benefits charge
              
              
              15
              
              
              29
              
              
              (14
              )Loss
                  on
                  reacquired debt
              
              
              40
              
              
              41
              
              
              (1
              )Employee
                  postretirement benefits costs
              
              
              53
              
              
              55
              
              
              (2
              )Nuclear
                  decommissioning, decontaminationand
                  spent fuel
                  disposal costs
              
              
              (129
              )
              
              (126
              )
              
              (3
              )Asset
                  removal
                  costs
              
              
              (164
              )
              
              (365
              )
              
              201Property
                  losses and unrecovered plant costs
              
              
              27
              
              
              29
              
              
              (2
              )MISO
                  transmission costs
              
              
              90
              
              
              91
              
              
              (1
              )RCP
                  fuel
                  recovery
              
              
              22
              
              
              -
              
              
              22RCP
                  distribution costs
              
              
              40
              
              
              -
              
              
              40JCP&L
                  reliability costs
              
              
              21
              
              
              23
              
              
              (2
              )Other
              
              
              34
              
              
              32
              
              
              2Total
              
              $
              4,396
              
              $
              4,486
              
              $
              (90
              )
 
 ***Reliability
        Initiatives***
  FirstEnergy
        is
        proceeding with the implementation of the recommendations that were issued
        from
        various entities, including governmental, industry and ad hoc reliability
        entities (PUCO, FERC, NERC and the U.S. - Canada Power System Outage Task
        Force)
        in late 2003 and early 2004, regarding enhancements to regional reliability
        that
        were to be completed subsequent to 2004. FirstEnergy will continue to
        periodically assess the FERC-ordered Reliability Study recommendations for
        forecasted 2009 system conditions, recognizing revised load forecasts and
        other
        changing system conditions which may impact the recommendations. Thus far,
        implementation of the recommendations has not required, nor is expected to
        require, substantial investment in new, or material upgrades to existing,
        equipment. The FERC or other applicable government agencies and reliability
        coordinators, however, may take a different view as to recommended enhancements
        or may recommend additional enhancements in the future as the result of adoption
        of mandatory reliability standards pursuant to EPACT that could require
        additional, material expenditures. Finally, the PUCO is continuing to review
        our
        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.
 
 As
        a result of
        outages experienced in JCP&L's service area in 2002 and 2003, the NJBPU had
        implemented reviews into JCP&L's service reliability. In 2004, the NJBPU
        adopted an MOU that set out specific tasks and a timetable for completion
        of
        actions related to service reliability to be performed by JCP&L and also
        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. JCP&L continues to file
        compliance reports reflecting activities associated with the MOU and
        Stipulation.
  47
 
 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. On December 30, 2005, the ALJ recommended
        that
        the PPUC adopt the Joint Petition for Settlement among the parties involved
        in
        the three Companies’ request to amend the distribution reliability benchmarks,
        thereby eliminating the need for full litigation. The ALJ’s recommendation,
        adopting the revised benchmarks and standards, was approved by the PPUC on
        February 9, 2006.
 
 EPACT
        provides for
        the creation of an ERO to establish and enforce reliability standards for
        the
        bulk power system, subject to FERC review. On February 3, 2006, the FERC
        adopted a rule establishing certification requirements for the ERO, as well
        as
        regional entities envisioned to assume monitoring responsibility for the
        new
        reliability standards. The FERC issued an order on rehearing on March 30,
        2006, providing certain clarifications and essentially affirming the
        rule.
 
 The
        NERC has been
        preparing the implementation aspects of reorganizing its structure to meet
        the
        FERC’s certification requirements for the ERO. The NERC made a filing with the
        FERC on April 4, 2006 to obtain certification as the ERO and to obtain FERC
        approval of delegation agreements with regional entities. The new FERC rule
        referred to above, further provides for reorganizing regional reliability
        organizations (regional entities) that would replace the current regional
        councils and for rearranging the relationship with the ERO. The “regional
        entity” may be delegated authority by the ERO, subject to FERC approval, for
        enforcing reliability standards adopted by the ERO and approved by the FERC.
        NERC also made a parallel filing with the FERC April 4, 2006 seeking approval
        of
        mandatory reliability standards. These
        reliability
        standards are based with some modifications, on the current NERC Version
        O
        reliability standards with some additional standards. On May 2, 2006, the
        NERC Board of Trustees adopted eight new cyber security standards and thirteen
        additional reliability standards. These standards will become effective on
        June 1, 2006 and will be filed with the FERC and relevant Canadian
        authorities for approval. The
        two filings are
        subject to review and acceptance by the FERC.
 
 The
        ERO filing was
        noticed on April 7, 2006 and comments and interventions were filed on
        May 4, 2006. There is no fixed time for the FERC to act on this filing. The
        reliability standards filing was noticed by FERC on April 18, 2006. In that
        notice FERC announced its intent to treat the proposed reliability standards
        as
        a NOPR and issue a NOPR in July 2006. Prior to that time, the FERC staff
        will release a preliminary assessment of the proposed reliability standards.
        FERC also intends to hold a technical conference on the proposed reliability
        standards. A comment period will be set after the Staff assessment is released
        and the technical conference is held. NERC has requested an effective date
        of
        January 1, 2007 for the reliability standards.
 
 The
        ECAR,
        Mid-Atlantic Area Council, and Mid-American Interconnected Network reliability
        councils have completed the consolidation of these regions into a single
        new
        regional reliability organization known as ReliabilityFirst Corporation.
        ReliabilityFirst began operations as a regional reliability council under
        NERC
        on January 1, 2006 and intends to file and obtain certification consistent
        with the final rule as a “regional entity” under the ERO during 2006. All of
        FirstEnergy’s facilities are located within the ReliabilityFirst
        region.
 
 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 standards. The financial
        impact of complying with the new standards cannot be determined at this time.
        However, EPACT requires that all prudent costs incurred to comply with the
        new
        reliability standards be recovered in rates. If FirstEnergy is unable to
        meet
        the reliability standards for the bulk power system in the future, it could
        have
        a material adverse effect on the Company’s and its subsidiaries’ financial
        condition, results of operations and cash flows.
 
 See
        Note 11 to
        the consolidated financial statements for a more detailed discussion of
        reliability initiatives.
 
 ***Ohio***
 
 On October 21, 2003 the Ohio Companies filed the RSP case with the PUCO.
        On
        August 5, 2004, the Ohio Companies accepted the RSP as modified and approved
        by
        the PUCO in an August 4, 2004 Entry on Rehearing, subject to a CBP. The RSP
        was
        intended to establish generation service rates beginning January 1, 2006,
        in response to 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 arguments on the appeals. On May 3, 2006, the Supreme Court
        of
        Ohio issued an opinion affirming that order with respect to the approval
        of the
        rate stabilization charge, approval of the shopping credits, the grant of
        interest on shopping credit incentive deferral amounts, and approval of
        FirstEnergy’s financial separation plan. It remanded the approval of the RSP
        pricing back to the PUCO for further consideration of the issue as to whether
        the RSP, as adopted by the PUCO, provided for sufficient customer participation
        in the competitive marketplace.
  48
  
 Under provisions of the RSP, the PUCO had required the Ohio Companies to
        undertake a CBP to secure generation and allow for customer pricing
        participation in the competitive marketplace. Any acceptance of future
        competitive bid results would terminate the RSP pricing, with no accounting
        impacts to the RSP, and not until 12 months after the PUCO authorizes such
        termination. On December 9, 2004, the PUCO rejected the auction price
        results from the CBP for the generation supply period beginning January 1,
        2006
        and issued an entry stating that the pricing under the approved revised RSP
        would take effect on January 1, 2006. On February 23, 2006 the CBP
        auction manager, National Economic Research Associates, notified the PUCO
        that a
        subsequent CBP to potentially provide firm generation service for the Ohio
        Companies' 2007 and 2008 actual load requirements could not proceed due to
        lack
        of interest, as there were no bidder applications submitted. Additionally,
        on
        March 20, 2006, the PUCO denied applications for rehearing filed by various
        parties regarding the PUCO's rules for the CBP. The above May 3, 2006
        Supreme Court of Ohio opinion may require the PUCO to reconsider this
        customer pricing process.
 
 On
        January 4, 2006,
        the PUCO approved, with modifications, the Ohio Companies' RCP to
        supplement the RSP to provide customers with more certain rate levels than
        otherwise available under the RSP during the plan period. Major provisions
        of
        the RCP include:
 
 ·
              Maintaining
                  the existing level of base distribution rates through December 31,
                  2008 for OE and TE, and April 30, 2009 for
                  CEI;
 
 ·
              Deferring
                  and
                  capitalizing for future recovery (over a 25-year period) with carrying
                  charges certain distribution costs to be incurred during the period
                  January 1, 2006 through December 31, 2008, not to exceed
                  $150 million in each of the three
                  years;
 
 ·
              Adjusting
                  the
                  RTC and extended RTC recovery periods and rate levels so that full
                  recovery of authorized costs will occur as of December 31, 2008 for
                  OE and TE and as of December 31, 2010 for
                  CEI;
 
 ·
              Reducing
                  the
                  deferred shopping incentive balances as of January 1, 2006 by up to
                  $75 million for OE, $45 million for TE, and $85 million for CEI
                  by accelerating the application of each respective company's accumulated
                  cost of removal regulatory liability;
                  and
 
 ·
              Recovering
                  increased fuel costs (compared to a 2002 baseline) of up to $75
                  million,
                  $77 million, and $79 million, in 2006, 2007, and 2008,
                  respectively, from all OE and TE distribution and transmission
                  customers
                  through a fuel recovery mechanism. OE, TE, and CEI may defer and
                  capitalize (for recovery over a 25-year period) increased fuel
                  costs above
                  the amount collected through the fuel recovery mechanism (in lieu
                  of
                  implementation of the GCAF rider).
 
 The
        following table
        provides the estimated net amortization of regulatory transition costs and
        deferred shopping incentives (including associated carrying charges) under
        the
        RCP for the period 2006 through 2010:
 
 **Amortization**
              
              
              
              
              
              
              
              **Total****Period**
              
              **OE**
              
              **CEI**
              
              **TE**
              
              **Ohio*****(In
                  millions)***2006
              
              $
              172
              
              $
              97
              
              $
              83
              
              $
              3522007
              
              
              180
              
              
              113
              
              
              90
              
              
              3832008
              
              
              206
              
              
              130
              
              
              108
              
              
              4442009
              
              
              -
              
              
              211
              
              
              -
              
              
              2112010
              
              
              -
              
              
              263
              
              
              -
              
              
              263**Total
                  Amortization**
              
              **$**
              **558**
              
              **$**
              **814**
              
              **$**
              **281**
              
              **$**
              **1,653**
 
 The
        PUCO’s January
        4, 2006 approval of the RCP also included approval of the Ohio
        Companies’ supplemental
        stipulation which was filed with the PUCO on November 4, 2005 and which was
        an
        additional component of the RCP filed on September 9, 2005. On
        January 10, 2006, the Ohio Companies filed a Motion for Clarification of
        the PUCO order approving the RCP. The Ohio Companies sought clarity on issues
        related to distribution deferrals, including requirements of the review process,
        timing for recognizing certain deferrals and definitions of the types of
        qualified expenditures. The Ohio Companies also sought confirmation that
        the
        list of deferrable distribution expenditures originally included in the revised
        stipulation fall within the PUCO order definition of qualified expenditures.
        On
        January 25, 2006, the PUCO issued an Entry on Rehearing granting in part,
        and denying in part, the Ohio Companies’ previous requests and clarifying issues
        referred to above. The PUCO granted the Ohio Companies’ requests to:
 
 ·
                Recognize
                    fuel
                    and distribution deferrals commencing January 1,
                    2006;·
                Recognize
                    distribution deferrals on a monthly basis prior to review by
                    the PUCO
                    Staff;
 49
  ·
                Clarify
                    that
                    the types of distribution expenditures included in the Supplemental
                    Stipulation may be deferred; and·
                Clarify
                    that
                    distribution expenditures do not have to be “accelerated” in order to be
                    deferred.
  The
        PUCO approved the Ohio Companies’ methodology for determining distribution
        deferral amounts, but denied the Motion in that the PUCO Staff must verify
        the
        level of distribution expenditures contained in current rates, as opposed
        to
        simply accepting the amounts contained in the Ohio Companies’ Motion. On
        February 3, 2006, several other parties filed applications for rehearing
        on the
        PUCO's January 4, 2006 Order. The Ohio Companies responded to the
        applications for rehearing on February 13, 2006. In an Entry on Rehearing
        issued by the PUCO on March 1, 2006, all motions for rehearing were denied.
        Certain of these parties have subsequently filed their notices of appeal
        with
        the Supreme Court of Ohio alleging various errors made by the PUCO in its
        order
        approving the RCP.
 
 On
        December 30,
        2004, the Ohio Companies filed with the PUCO two applications related to
        the
        recovery of transmission and ancillary service related costs. The first
        application sought recovery of these costs beginning January 1, 2006. The
        Ohio Companies requested that these costs be recovered through a rider that
        would be effective on January 1, 2006 and adjusted each July 1
        thereafter. The parties reached a settlement agreement that was approved
        by the
        PUCO on August 31, 2005. The incremental transmission and ancillary service
        revenues expected to be recovered from January through June 30, 2006 are
        approximately $66 million. This amount includes the recovery of the 2005
        deferred MISO expenses as described below. On May 1, 2006, the Ohio
        Companies filed a modification to the rider to 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 MISO,
        but
        only for those costs incurred during the period December 30, 2004 through
        December 31, 2005. Permission to defer costs incurred prior to
        December 30, 2004 was denied. The PUCO also authorized the Ohio Companies
        to accrue carrying charges on the deferred balances. On August 31, 2005,
        the OCC appealed the PUCO's decision. All briefs have been filed. On March
        20,
        2006, the Ohio Supreme Court, on its own motion, consolidated the OCC's appeal
        of the Ohio Companies' case with a similar case involving Dayton Power &
Light Company. Oral arguments are currently scheduled for May 10, 2006.
 
 On
        January 20,
        2006 the OCC sought rehearing of the PUCO approval of the recovery of deferred
        costs through the rider during the period January 1, 2006 through June 30,
        2006. The PUCO denied the OCC's application on February 6, 2006. On March
        23, 2006, the OCC appealed the PUCO's order to the Ohio Supreme Court. The
        OCC's
        brief is expected to be filed during the second quarter of 2006. The briefs
        of the PUCO and the Ohio Companies will be due within thirty days of the
        OCC's
        filing. On March 27, 2006, the OCC filed a motion to consolidate this appeal
        with the deferral appeals discussed above and to postpone oral arguments
        in the
        deferral appeal until after all briefs are filed in this most recent appeal
        of
        the rider recovery mechanism. On April 18, 2006, the Court denied both parts
        of
        the motion but on its own motion consolidated the OCC's appeal of the Ohio
        Companies' case with a similar case of Dayton Power & Light Company and
        stayed briefing on these appeals.
 
 See
        Note 11 to
        the consolidated financial statements for further details and a complete
        discussion of regulatory matters in Ohio.
 
 ***Pennsylvania***
  As
        of March 31,
        2006, Met-Ed's and Penelec's regulatory deferrals pursuant to the 1998
        Restructuring Settlement (including the Phase 2 Proceedings) and the
        FirstEnergy/GPU Merger Settlement Stipulation are $328 million and
        $50 million, respectively. Penelec's $50 million is subject to the pending
        resolution of taxable income issues associated with NUG trust fund proceeds.
 
 On January 12, 2005, Met-Ed and Penelec filed, before the PPUC, a request
        for
        deferral of transmission-related costs beginning January 1, 2005. The OCA,
        OSBA,
        OTS, MEIUG, PICA, Allegheny Electric Cooperative and Pennsylvania Rural Electric
        Association have all intervened in the case. As of March 31, 2006, the PPUC
        had
        taken no action on the request and neither company had yet implemented deferral
        accounting for these costs. Met-Ed and Penelec sought to consolidate this
        proceeding (and modified their request to provide deferral of 2006
        transmission-related costs only) with the comprehensive rate filing they
        made on
        April 10, 2006 as described below. On May 4, 2006, the PPUC approved
        the modified request. Accordingly, Met-Ed and Penelec will implement deferral
        accounting for these costs in the second quarter of 2006, which will include
        $24
        million and $4 million, respectively, representing the amounts that were
        incurred in the first quarter of 2006 -- the deferrals of such amounts will
        be reflected in the second quarter of 2006.
  50
 
 Met-Ed
        and Penelec
        purchase a portion of their PLR requirements from FES through a wholesale
        power
        sales agreement. Under this agreement, FES retains the supply obligation
        and the
        supply profit and loss risk for the portion of power supply requirements
        not
        self-supplied by Met-Ed and Penelec under their contracts with NUGs and other
        unaffiliated suppliers. The FES arrangement reduces Met-Ed's and Penelec's
        exposure to high wholesale power prices by providing power at a fixed price
        for
        their uncommitted PLR energy costs during the term of the agreement with
        FES.
        The wholesale power sales agreement with FES could automatically be extended
        for
        each successive calendar year unless any party elects to cancel the agreement
        by
        November 1 of the preceding year. On November 1, 2005, FES and the other
        parties thereto amended the agreement to provide FES the right in 2006 to
        terminate the agreement at any time upon 60 days notice. On April 7, 2006,
        the parties to the wholesale power sales agreement entered into a Tolling
        Agreement that arises out of FES’ notice to Met-Ed and Penelec that FES elected
        to exercise its right to terminate the wholesale power sales agreement effective
        midnight December 31, 2006, because that agreement is not economically
        sustainable to FES.
 
 In
        lieu of allowing
        such termination to become effective as of December 31, 2006, the parties
        agreed, pursuant to the Tolling Agreement, to amend the wholesale power sales
        agreement to provide as follows:
 
 1.  The
        termination
        provisions of the wholesale power sales agreement will be tolled for one
        year
        until December 31, 2007, provided that during such tolling
        period:
 
 a.
            FES
                will be
                permitted to terminate the wholesale power sales agreement at any
                time
                with sixty days written notice; b.
            Met-Ed
                and
                Penelec will procure through arrangements other than the wholesale
                power
                sales agreement beginning December 1, 2006 and ending December 31,
                2007,
                approximately 33% of the amounts of capacity and energy necessary
                to
                satisfy their PLR obligations for which Committed Resources (i.e.,
                non-utility generation under contract to Met-Ed and Penelec, Met-Ed-
                and
                Penelec-owned generating facilities, purchased power contracts and
                distributed generation) have not been obtained;
                and c.
            FES
                will not
                be obligated to supply additional quantities of capacity and energy
                in the
                event that a supplier of Committed Resources defaults on its supply
                agreement. 
 2.  During
        the tolling
        period FES will not act as agent for Met-Ed or Penelec in procuring the services
        under section 1.(b) above; and
 
 3.  The
        pricing
        provision of the wholesale power sales agreement shall remain unchanged provided
        Met-Ed and Penelec comply with the provisions of the Tolling Agreement and
        any
        applicable provision of the wholesale power sales agreement.
 
 In
        the event that
        FES elects not to terminate the wholesale power sales agreement effective
        midnight December 31, 2007, similar tolling agreements effective after
        December 31, 2007 are expected to be considered by FES for subsequent years
        if
        Met-Ed and Penelec procure through arrangements other than the wholesale
        power
        sales agreement approximately 64%, 83% and 95% of the additional amounts
        of
        capacity and energy necessary to satisfy their PLR obligations for 2008,
        2009
        and 2010, respectively, for which Committed Resources have not been obtained
        from the market.
 
 The
        wholesale power
        sales agreement, as modified by the Tolling Agreement, requires Met-Ed and
        Penelec to satisfy the portion of their PLR obligations currently supplied
        by
        FES from unaffiliated suppliers at prevailing prices, which are likely to
        be
        higher than the current price charged by FES under the current agreement
        and, as
        a result, Met-Ed’s and Penelec’s purchased power costs could materially
        increase. If Met-Ed and Penelec were to replace the entire FES supply at
        current
        market power prices without corresponding regulatory authorization to increase
        their generation prices to customers, each company would likely incur a
        significant increase in operating expenses and experience a material
        deterioration in credit quality metrics. Under such a scenario, each company's
        credit profile would no longer be expected to support an investment grade
        rating
        for its fixed income securities. There can be no assurance, however, that
        if FES
        ultimately determines to terminate, or significantly modify the agreement,
        timely regulatory relief will be granted by the PPUC pursuant to the April
        10,
        2006 comprehensive rate filing discussed below, or, to the extent granted,
        adequate to mitigate such adverse consequences.
 
 Met-Ed
        and Penelec
        made a comprehensive rate filing with the PPUC on April 10, 2006 that
        addresses a number of transmission, distribution and supply issues. If Met-Ed's
        and Penelec's preferred approach involving accounting deferrals is approved,
        the
        filing would increase annual revenues by $216 million and $157 million,
        respectively. That filing includes, among other things, a request to charge
        customers for an increasing amount of market priced power procured through
        a
        competitive bid process as the amount of supply provided under the existing
        FES
        agreement is phased out in accordance with the April 7, 2006 Tolling agreement
        described above. Met-Ed
        and Penelec
        also requested approval of the January 12, 2005 petition for the deferral
        of
        transmission-related costs discussed above, but only for those costs incurred
        during 2006. In this rate filing, Met-Ed and Penelec also requested recovery
        of
        annual transmission and related costs incurred on or after January 1, 2007,
        plus the amortized portion of 2006 costs over a ten-year period, along with
        applicable carrying charges, through an adjustable rider similar to that
        implemented in Ohio. Changes in the
        recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs
        are
        also included in the filing. The filing contemplates a reduction in distribution
        rates for Met-Ed in the amount of $37 million annually and an increase in
        distribution rates for Penelec in the amount of $20 million annually.
        Although the companies have proposed an effective date of June 10, 2006, it
        is expected that the PPUC will suspend the effective date for seven months
        as
        permitted under Pennsylvania law. Hearings are expected to be scheduled for
        the
        second half of 2006 and a PPUC decision is expected early in the first quarter
        of 2007.
   51
  On
        October 11,
        2005, Penn filed a plan with the PPUC to secure electricity supply for its
        customers at set rates following the end of its transition period on
        December 31, 2006. Penn recommended that the RFP process cover the period
        January 1, 2007 through May 31, 2008. Hearings were held on
        January 10, 2006 with main briefs filed on January 27, 2006 and reply
        briefs filed on February 3, 2006. On February 16, 2006, the ALJ issued a
        Recommended Decision to adopt Penn's RFP process with modifications. The
        PPUC
        approved the Recommended Decision with additional modifications on
        April 20, 2006. The approved plan is designed to provide customers with PLR
        service for 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 11 to
        the consolidated financial statements for further details and a complete
        discussion of regulatory matters in Pennsylvania.
 
 ***New
        Jersey***
 
 JCP&L
        is
        permitted to defer for future collection from customers the amounts by which
        its
        costs of supplying BGS to non-shopping customers and costs incurred under
        NUG
        agreements exceed amounts collected through BGS and NUGC rates and market
        sales
        of NUG energy and capacity. As of March 31, 2006, the accumulated deferred
        cost
        balance totaled approximately $558 million. New Jersey law allows for
        securitization of JCP&L's deferred balance upon application by JCP&L and
        a determination by the NJBPU that the conditions of the New Jersey restructuring
        legislation are met. On February 14, 2003, JCP&L filed for approval to
        securitize the July 31, 2003 deferred balance. On December 2, 2005,
        JCP&L filed a request for recovery of $165 million of actual
        above-market NUG costs incurred from August 1, 2003 through
        October 31, 2005 and forecasted above-market NUG costs for November and
        December 2005. On February 1, 2006, the NJBPU selected Bear Stearns as the
        financial advisor. Meetings with the NJBPU Staff and the DRA were held during
        March and April and additional discovery conducted. The DRA filed comments
        on
        April 6, 2006, arguing that the proposed securitization does not produce
        customer savings. JCP&L submitted reply comments on April 10, 2006. On
        February 23, 2006, JCP&L filed updated data reflecting actual amounts
        through December 31, 2005 of $154 million of cost incurred since July
        31, 2003. The filing also includes a request for recovery of $49 million
        for above-market NUG costs incurred prior to August 1, 2003, to the extent
        those costs are not recoverable through securitization. On March 29, 2006,
        a pre-hearing conference was held with the presiding ALJ. A schedule for
        the
        proceeding was established including a discovery period and evidentiary hearings
        scheduled for September 2006.
 
 An
        NJBPU Decision
        and Order approving a Phase II Stipulation of Settlement and resolving the
        Motion for Reconsideration of the Phase I Order was issued on May 31, 2005.
        The
        Phase II Settlement includes a performance standard pilot program with potential
        penalties of up to 0.25% of equity return. The Order requires that JCP&L
        file quarterly reliability reports (CAIDI and SAIFI information related to
        the
        performance pilot program) through December 2006 and updates to reliability
        related project expenditures until all projects are completed. The first
        quarterly report was submitted to NJBPU on August 16, 2005. The second quarterly
        report was submitted on November 22, 2005. The third quarterly report as of
        December 31, 2005 was submitted on March 28, 2006. As of December 31, 2005
        there were no performance penalties issued by the NJBPU.
 
 On
        August 1,
        2005, the NJBPU established a proceeding to determine whether additional
        ratepayer protections are required at the state level in light of the recent
        repeal of PUHCA under the EPACT. An NJBPU proposed rulemaking to address
        the
        issues was published in the NJ Register on December 19, 2005. The proposal
        would prevent a holding company that owns a gas or electric public utility
        from
        investing more than 25% of the combined assets of its utility and
        utility-related subsidiaries into businesses unrelated to the utility industry.
        A public hearing was held February 7, 2006 and comments were submitted to
        the NJBPU. The
        NJBPU Staff issued a draft proposal on March 31, 2006 addressing various
        issues including access to books and records, ring-fencing, cross subsidization,
        corporate governance and related matters. Comments and reply comments are
        due by
        May 22 and May 31, 2006, respectively. JCP&L is not able to predict the
        outcome of this proceeding at this time.
 
 See
        Note 11 to
        the consolidated financial statements for further details and a complete
        discussion of regulatory matters in New Jersey.
  52
 
 ***FERC
        Matters***
  On
        November 18,
        2004, the FERC issued an order eliminating the regional through and out rates
        (RTOR) for transmission service between the MISO and PJM regions. The FERC
        also
        ordered the MISO, PJM and the transmission owners within the MISO and PJM
        to
        submit compliance filings containing a mechanism - the Seams Elimination
        Cost
        Adjustment (SECA) -- to recover lost RTOR revenues during a 16-month transition
        period from load serving entities. The FERC issued orders in 2005 setting
        the
        SECA for hearing. ATSI, JCP&L, Met-Ed, Penelec, and FES continue to be
        involved in the FERC hearings concerning the calculation and imposition of
        the
        SECA charges. The hearing began on May 1, 2006. The FERC has ordered the
        Presiding Judge to issue an initial decision by August 11,
        2006.
 
 On
        November 1, 2004,
        ATSI filed with FERC a request to defer approximately $54 million of costs
        to be incurred from 2004 through 2007 in connection with ATSI’s Vegetation
        Management Enhancement Project (VMEP), which represents ATSI’s adoption of newly
        identified industry “best practices” for vegetation management. On March 4,
        2005, the FERC approved ATSI’s request to defer the VMEP costs (approximately
        $29 million deferred as of March 31, 2006). On March 28, 2006 ATSI
        and MISO filed with FERC a request to modify ATSI’s Attachment O formula
        rate to include revenue requirements associated with recovery of deferred
        VMEP
        costs over a five-year period. The requested effective date to begin recovery
        is
        June 1, 2006. Various parties have filed comments responsive to the
        March 28, 2006 submission. The FERC has not taken any action on the filing.
        The estimated impact of the VMEP cost recovery is $13 million in revenues
        annually during the five-year recovery period of June 1, 2006 to
        May 31, 2011.
 
 On
        January 24,
        2006, ATSI and MISO filed with FERC a request to correct ATSI’s Attachment O
        formula rate to reverse revenue credits associated with termination of revenue
        streams from transitional rates stemming from FERC’s elimination of through and
        out rates. Revenues formerly collected under these rates were included in,
        and
        served to reduce, ATSI’s zonal transmission rate under the Attachment O formula.
        Absent the requested correction, elimination of these revenue streams would
        not
        be fully reflected in ATSI’s formula rate until June 1, 2008. On March 16,
        2006, FERC approved without suspension the revenue credit correction, which
        became effective April 1, 2006. One party sought rehearing of the FERC order.
        The FERC has not yet issued a further order. The estimated impact of the
        correction mechanism is approximately $40 million in revenues on an annualized
        basis beginning June 1, 2006.
 
 On
        January 31,
        2005, certain PJM transmission owners made three filings with the FERC pursuant
        to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and
        Penelec were parties to that proceeding and joined in two of the filings.
        In the
        first filing, the settling transmission owners submitted a filing justifying
        continuation of their existing rate design within the PJM RTO. In the second
        filing, the settling transmission owners proposed a revised Schedule 12 to
        the PJM tariff designed to harmonize the rate treatment of new and existing
        transmission facilities. Interventions and protests were filed on
        February 22, 2005. In the third filing, Baltimore Gas and Electric Company
        and Pepco Holdings, Inc. requested a formula rate for transmission service
        provided within their respective zones. On May 31, 2005, the FERC issued an
        order on these cases. First, it set for hearing the existing rate design
        and
        indicated that it will issue a final order within six months. American
        Electric
        Power Company, Inc. filed in opposition proposing to create a "postage stamp"
        rate for high voltage transmission facilities across PJM. Second, the FERC
        approved the proposed Schedule 12 rate harmonization. Third, the FERC accepted
        the proposed formula rate, subject to referral and hearing procedures. On
        June 30, 2005, the settling PJM transmission owners filed a request for
        rehearing of the May 31, 2005 order. On
        March 20, 2006 a settlement was filed with FERC in the formula rate
        proceeding that generally accepts the companies' formula rate proposal. The
        FERC
        issued an order approving this settlement on April 19, 2006. If the FERC
        accepts AEP's proposal, significant additional transmission revenues would
        be
        imposed on JCP&L, Met-Ed, Penelec, and other transmission zones within
        PJM.
 
 On
        November 1, 2005,
        FES filed two power sales agreements for approval with the FERC. One power
        sales
        agreement provided for FES to provide the PLR requirements of the Ohio Companies
        at a price equal to the retail generation rates approved by the PUCO for
        a
        period of three years beginning January 1, 2006. The Ohio Companies will be
        relieved of their obligation to obtain PLR power requirements from FES if
        the
        Ohio competitive bid process results in a lower price for retail customers.
        A
        similar power sales agreement between FES and Penn permits Penn to obtain
        its
        PLR power requirements from FES at a fixed price equal to the retail generation
        price during 2006. The PPUC approved Penn's plan with modifications on April
        20,
        2006 to use an RFP process to obtain its power supply requirements after
        2006.
 
 On
        December 29,
        2005, the FERC issued an order setting the two power sales agreements for
        hearing. The order criticized the Ohio competitive bid process, and required
        FES
        to submit additional evidence in support of the reasonableness of the prices
        charged in the power sales agreements. A pre-hearing conference was held
        on
        January 18, 2006 to determine the hearing schedule in this case. FES
        expects an initial decision to be issued in this case in late January 2007,
        as a
        result of an April 20, 2006 extension of the procedural schedule. The outcome
        of
        this proceeding cannot be predicted. FES has sought rehearing of the
        December 29, 2005 order and the FERC granted rehearing for further
        consideration on March 1, 2006.
  53
 
 ***Environmental
        Matters***
 
 The
        Companies accrue
        environmental liabilities only when 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.
 
 On
        December 1,
        2005, FirstEnergy issued a comprehensive report to shareholders regarding
        air
        emissions regulations and an assessment of future risks and mitigation efforts.
        The report is available on FirstEnergy's web site at
        www.firstenergycorp.com/environmental.
 
 *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 CAIR covering a
        total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania)
        and
        the District of Columbia based on proposed findings that air emissions from
        28 eastern states and the District of Columbia significantly contribute to
        non-attainment of the NAAQS for fine particles and/or the "8-hour" ozone
        NAAQS
        in other states. CAIR provides each affected state until 2006 to develop
        implementing regulations to achieve additional reductions of NO X and SO 2 emissions in two
        phases (Phase I in 2009 for NO X ,
        2010 for
        SO 2 and Phase II in
        2015 for both NO X and SO 2 ).
        FirstEnergy's
        Michigan, Ohio and Pennsylvania fossil-fired generation facilities will be
        subject to caps on SO 2 and
        NO X emissions, whereas
        its New Jersey fossil-fired generation 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 CAMR, which provides for a cap-and-trade program to reduce mercury
        emissions from coal-fired power plants in two phases. Initially, mercury
        emissions will be capped nationally at 38 tons by 2010 (as a "co-benefit"
        from implementation of SO 2 and NO X emission caps under
        the EPA's CAIR program). Phase II of the mercury cap-and-trade program will
        cap
        nationwide mercury emissions from coal-fired power plants at 15 tons per
        year by 2018. However, the final rules give states substantial discretion
        in
        developing rules to implement these programs. In addition, both CAIR and
        CAMR
        have been challenged in the United States Court of Appeals for the District
        of
        Columbia. FirstEnergy's future cost of compliance with these regulations
        may be
        substantial and will depend on how they are ultimately implemented by the
        states
        in which FirstEnergy operates affected facilities.
 
 The model rules for both CAIR and CAMR contemplate an input-based methodology
        to
        allocate allowances to affected facilities. Under this approach, allowances
        would be allocated based on the amount of fuel consumed by the affected sources.
        FirstEnergy would prefer an output-based generation-neutral methodology in
        which
        allowances are allocated based on megawatts of power produced. Since this
        approach is based on output, new and non-emitting generating facilities,
        including renewables and nuclear, would be entitled to their proportionate
        share
        of the allowances. Consequently, FirstEnergy would be disadvantaged if these
        model rules were implemented because FirstEnergy's substantial reliance on
        non-emitting (largely nuclear) generation is not recognized under the
        input-based allocation.
 
 *W.
        H. Sammis
        Plant*
 
 In
        1999 and 2000,
        the EPA issued NOV or Compliance Orders to nine utilities alleging violations
        of
        the Clean Air Act based on operation and maintenance of 44 power plants,
        including the W. H. Sammis Plant, which was owned at that time by OE and
        Penn.
        In addition, the DOJ filed eight civil complaints against various investor-owned
        utilities, including a complaint against OE and Penn in the U.S. District
        Court
        for the Southern District of Ohio. These cases are referred to as New Source
        Review cases. On March 18, 2005, OE and Penn announced that they had
        reached a settlement with the EPA, the DOJ and three states (Connecticut,
        New
        Jersey, and New York) that resolved all issues related to the W. H. Sammis
        Plant
        New Source Review litigation. This settlement agreement was approved by the
        Court on July 11, 2005, and requires reductions of NO X and SO 2 emissions at the
        W. H. Sammis Plant and other coal fired plants through the installation of
        pollution control devices and provides for stipulated penalties for failure
        to
        install and operate such pollution controls in accordance with that agreement.
        Consequently, if FirstEnergy fails to install such pollution control devices,
        for any reason, including, but not limited to, the failure of any third-party
        contractor to timely meet its delivery obligations for such devices, FirstEnergy
        could be exposed to penalties under the settlement agreement. Capital
        expenditures necessary to meet those requirements are currently estimated
        to be
        $1.5 billion (the primary portion of which is expected to be spent in the
        2008 to 2011 time period). On 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 paid by OE and Penn of $7.8 million
        and $0.7 million, respectively. OE and Penn also recognized liabilities in
        the first quarter of 2005 of $9.2 million and $0.8 million,
        respectively, for probable future cash contributions toward environmentally
        beneficial projects.
 
 54
 *Climate
        Change*
  In
        December 1997,
        delegates to the United Nations' climate summit in Japan adopted an agreement,
        the Kyoto Protocol, to address global warming by reducing the amount of man-made
        GHG emitted by developed countries by 5.2% from 1990 levels between 2008
        and
        2012. The United States signed the Kyoto Protocol in 1998 but it failed to
        receive the two-thirds vote of the United States Senate required for
        ratification. However, the Bush administration has committed the United States
        to a voluntary climate change strategy to reduce domestic GHG intensity -
        the
        ratio of emissions to economic output - by 18% through 2012. The EPACT
        established a Committee on Climate Change Technology to coordinate federal
        climate change activities and promote the development and deployment of GHG
        reducing technologies.
 
 FirstEnergy
        cannot
        currently estimate the financial impact of climate change policies, although
        the
        potential restrictions on CO 2 emissions could
        require significant capital and other expenditures. However, the CO 2 emissions per
        kilowatt-hour of electricity generated by 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
        March 31, 2006, based on estimates of the total costs of cleanup, the
        Companies' proportionate responsibility for such costs and the financial
        ability
        of other unaffiliated entities to pay. In addition, JCP&L has accrued
        liabilities for environmental remediation of former manufactured gas plants
        in
        New Jersey. Those costs are being recovered by JCP&L through a
        non-bypassable SBC. Total liabilities of approximately $63 million have
        been accrued through March 31, 2006.
 
 See Note 1 0(B)
        to the
        consolidated financial statements for further details and a complete discussion
        of environmental matters.
 
 ***Other
        Legal Proceedings***
 
 *Power
        Outages
        and Related Litigation*
 
 On
        August 14,
        2003, various states and parts of southern Canada experienced widespread
        power
        outages. The outages affected approximately 1.4 million customers in
        FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s
        final report in April 2004 on the outages concluded, among other things,
        that
        the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically,
        the
        final report concluded, among other things, that the initiation of the
        August 14, 2003 power outages resulted from an alleged failure of both
        FirstEnergy and ECAR to assess and understand perceived inadequacies within
        the
        FirstEnergy system; inadequate situational awareness of the developing
        conditions; and a perceived failure to adequately manage tree growth in certain
        transmission rights of way. The Task Force also concluded that there was
        a
        failure of the interconnected grid's reliability organizations (MISO and
        PJM) to
        provide effective real-time diagnostic support. The final report is publicly
        available through the Department of Energy’s 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
        March 31, 2006 for any expenditure 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.
  55
 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 Company, Inc. as well) for claims paid to insureds
        for
        damages allegedly arising as a result of the loss of power on August 14,
        2003. The listed insureds in these cases, in many instances, are not customers
        of any FirstEnergy company. The fourth case involves the claim of a non-customer
        seeking reimbursement for losses incurred when its store was burglarized
        on
        August 14, 2003. On
        March 7,
        2006, the PUCO issued a ruling applicable to all pending cases. Among its
        various rulings, the PUCO consolidated all of the pending outage cases for
        hearing; limited the litigation to service-related claims by customers of
        the
        Ohio operating companies; dismissed FirstEnergy Corp. as a defendant; ruled
        that
        the U.S.-Canada Power System Outage Task Force Report was not admissible
        into
        evidence; and gave the plaintiffs additional time to amend their complaints
        to
        otherwise comply with the PUCO’s underlying order. The plaintiffs in
        one case have since filed an amended complaint. The named FirstEnergy companies
        have answered and also have filed a motion to dismiss the action, which is
        pending. Also, most complainants, along with the FirstEnergy companies, filed
        applications for rehearing with the PUCO over various rulings contained in
        the
        March 7, 2006 order. On April 26, 2006, the PUCO granted rehearing to allow
        the insurance company claimants, as insurers, to prosecute their claims in
        their
        name so long as they also identify the underlying insured entities and the
        Ohio
        utilities which provide their service. The PUCO denied all other motions
        for
        rehearing. No estimate of potential liability is available for any of these
        cases. 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.
        Following the PUCO's March 7, 2006 order, that action was voluntarily
        dismissed by the claimants.
 
 In
        addition to the
        above proceedings, FirstEnergy 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 has been filed. FirstEnergy was also named,
        along with several other entities, in a complaint in New Jersey State Court.
        The
        allegations against FirstEnergy are based, in part, on an alleged failure
        to
        protect the citizens of Jersey City from an electrical power outage. No
        FirstEnergy entity serves any customers in Jersey City. A responsive pleading
        has been filed. On April 28, 2006, the Court granted FirstEnergy's motion
        to dismiss. It is uncertain whether the plaintiff will appeal. No estimate
        of
        potential liability has been undertaken in either of these matters.
 
 FirstEnergy
        is
        vigorously defending these actions, but cannot predict the outcome of any
        of
        these proceedings or whether any further regulatory proceedings or legal
        actions
        may be initiated against the Companies. Although unable to predict the impact
        of
        these proceedings, if FirstEnergy or its subsidiaries were ultimately determined
        to have legal liability in connection with these proceedings, it could have
        a
        material adverse effect on FirstEnergy's or its subsidiaries' financial
        condition, results of operations and cash flows.
 
 *Nuclear
        Plant
        Matters*
 
 On
        January 20,
        2006, FENOC announced that it has entered into a deferred prosecution agreement
        with the U.S. Attorney’s Office for the Northern District of Ohio and the
        Environmental Crimes Section of the Environment and Natural Resources Division
        of the DOJ related to FENOC’s communications with the NRC during the fall of
        2001 in connection with the reactor head issue at the Davis-Besse Nuclear
        Power
        Station. Under the agreement, which expires on December 31, 2006, the
        United States acknowledged FENOC’s extensive corrective actions at Davis-Besse,
        FENOC’s cooperation during investigations by the DOJ and the NRC, FENOC’s pledge
        of continued cooperation in any related criminal and administrative
        investigations and proceedings, FENOC’s acknowledgement of responsibility for
        the behavior of its employees, and its agreement to pay a monetary penalty.
        The
        DOJ will refrain from seeking an indictment or otherwise initiating criminal
        prosecution of FENOC for all conduct related to the statement of facts attached
        to the deferred prosecution agreement, as long as FENOC remains in compliance
        with the agreement, which FENOC fully intends to do. FENOC paid a monetary
        penalty of $28 million (which is not deductible for income tax purposes)
        which reduced First Energy's earnings by $0.09 per common share in the fourth
        quarter of 2005.
   56
  On
        April 21,
        2005, the NRC issued a NOV and proposed a $5.45 million civil penalty
        related to the degradation of the Davis-Besse reactor vessel head issue
        discussed above. FirstEnergy accrued $2 million for a potential fine prior
        to 2005 and accrued the remaining liability for the proposed fine during
        the
        first quarter of 2005. On September 14, 2005, FENOC filed its response to
        the NOV with the NRC. FENOC accepted full responsibility for the past failure
        to
        properly implement its boric acid corrosion control and corrective action
        programs. The NRC NOV indicated that the violations do not represent current
        licensee performance. FirstEnergy paid the penalty in the third quarter of
        2005.
        On January 23, 2006, FENOC supplemented its response to the NRC's NOV on
        the Davis-Besse head degradation to reflect the deferred prosecution agreement
        that FENOC had reached with the DOJ.
 
 On
        August 12,
        2004, the NRC notified FENOC that it would increase its regulatory oversight
        of
        the Perry Nuclear Power Plant as a result of problems with safety system
        equipment over the preceding two years and the licensee's failure to take
        prompt
        and corrective action. FENOC operates the Perry Nuclear Power Plant.
 
 On
        April 4,
        2005, the NRC held a public meeting to discuss FENOC’s performance at the Perry
        Nuclear Power Plant as identified in the NRC's annual assessment letter to
        FENOC. Similar public meetings are held with all nuclear power plant licensees
        following issuance by the NRC of their annual assessments. According to the
        NRC,
        overall the Perry 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. By an inspection report dated January 18, 2006, the NRC closed one
        of the White Findings (related to emergency preparedness) which led to the
        multiple degraded cornerstones.
 
 On
        September 28, 2005, the NRC sent a CAL to FENOC describing commitments that
        FENOC had made to improve the performance at the Perry Plant and stated that
        the
        CAL would remain open until substantial improvement was demonstrated. The
        CAL
        was anticipated as part of the NRC's Reactor Oversight Process. In the NRC's
        2005 annual assessment letter dated March 2, 2006 and associated meetings
        to
        discuss the performance of Perry on March 14, 2006, the NRC again stated
        that the Perry Plant continued to operate in a manner that "preserved public
        health and safety." However, the NRC also stated that increased levels of
        regulatory oversight would continue until sustained improvement in the
        performance of the facility was realized. If performance does not improve,
        the
        NRC has a range of options under the Reactor Oversight Process, from increased
        oversight to possible impact to the plant’s operating authority. Although
        FirstEnergy is unable to predict the impact of the ultimate disposition of
        this
        matter, it could have a material adverse effect on FirstEnergy's or its
        subsidiaries' financial condition, results of operations and cash
        flows.
 
 As
        of
        December 16, 2005, NGC acquired ownership of the nuclear generation assets
        transferred from OE, CEI, TE and Penn with the exception of leasehold interests
        of OE and TE in certain of the nuclear plants that are subject to sale and
        leaseback arrangements with non-affiliates.
 
 *Other
        Legal
        Matters*
 
 There
        are various
        lawsuits, claims (including claims for asbestos exposure) and proceedings
        related to FirstEnergy’s normal business operations pending against FirstEnergy
        and its subsidiaries. The other material items not otherwise discussed above
        are
        described below.
 
 On
        October 20,
        2004, FirstEnergy was notified by the SEC that the previously disclosed informal
        inquiry initiated by the SEC's Division of Enforcement in September 2003
        relating to the restatements in August 2003 of previously reported results
        by
        FirstEnergy and the Ohio Companies, and the Davis-Besse extended outage,
        have
        become the subject of a formal order of investigation. The SEC's formal order
        of
        investigation also encompasses issues raised during the SEC's examination
        of
        FirstEnergy and the Companies under PUHCA. Concurrent with this notification,
        FirstEnergy received a subpoena asking for background documents and documents
        related to the restatements and Davis-Besse issues. On December 30, 2004,
        FirstEnergy received a subpoena asking for documents relating to issues raised
        during the SEC's PUHCA examination. On August 24, 2005 additional
        information was requested regarding Davis-Besse related disclosures, which
        FirstEnergy has provided. FirstEnergy has cooperated fully with the informal
        inquiry and will continue to do so with the formal investigation.
  57
 
 On
        August 22,
        2005, a class action complaint was filed against OE in Jefferson County,
        Ohio
        Common Pleas Court, seeking compensatory and punitive damages to be determined
        at trial based on claims of negligence and eight other tort counts alleging
        damages from W.H. Sammis Plant air emissions. The two named plaintiffs are
        also
        seeking injunctive relief to eliminate harmful emissions and repair property
        damage and the institution of a medical monitoring program for class members.
 
 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 million to the bargaining unit employees. On February 6, 2006, the
        federal court granted a Union motion to dismiss JCP&L's appeal of the award
        as premature. JCP&L will file its appeal again in federal district court
        once the damages associated with this case are identified at an individual
        employee level. JCP&L recognized a liability for the potential
        $16 million award in 2005.
 
 The
        City of Huron
        filed a complaint against OE with the PUCO challenging the ability of electric
        distribution utilities to collect transition charges from a customer of a
        newly
        formed municipal electric utility. The complaint was filed on May 28, 2003,
        and OE timely filed its response on June 30, 2003. In a related filing, the
        Ohio Companies filed for approval with the PUCO 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 decide 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 10(C)
        to the consolidated financial statements for further details and a complete
        discussion of these and other legal proceedings.
 
 **NEW
        ACCOUNTING STANDARDS AND INTERPRETATIONS**
 
 *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. This EITF issue will not have a material impact on
        FirstEnergy's financial results.
 
 *SFAS
        155 -
“Accounting for Certain Hybrid Financial Instruments-an amendment of FASB
        Statements No. 133 and 140”*
  In February 2006, the FASB issued SFAS 155 which amends SFAS 133 “Accounting for
        Derivative Instruments and Hedging Activities,” (SFAS 133) and SFAS 140
“Accounting for Transfers and Servicing of Financial Assets and Extinguishments
        of Liabilities.” This Statement permits fair value remeasurement for any hybrid
        financial instrument that contains an embedded derivative that otherwise
        would
        require bifurcation, clarifies which interest-only strips and principal-only
        strips are not subject to the requirements of SFAS 133, establishes a
        requirement to evaluate interests in securitized financial assets to identify
        interests that are freestanding derivatives or that are hybrid financial
        instruments that contain an embedded derivative requiring bifurcation, clarifies
        that concentrations of credit risk in the form of subordination are not embedded
        derivatives and amends SFAS 140 to eliminate the prohibition on a qualifying
        special-purpose entity from holding a derivative financial instrument that
        pertains to a beneficial interest other than another derivative instrument.
        This
        Statement is effective for all financial instruments acquired or issued
        beginning January 1, 2007. FirstEnergy is currently evaluating the impact
        of this Statement on its financial statements.
  58
   **OHIO
                  EDISON COMPANY****CONSOLIDATED
                  STATEMENTS OF INCOME AND COMPREHENSIVE
                  INCOME****(Unaudited)****Three
                  Months Ended****March
                  31,****2006**
              
              **2005****STATEMENTS
                  OF INCOME**
              
              ***(In
                  thousands)*****OPERATING
                  REVENUES**
              
              $
              586,203
              
              $
              726,358**OPERATING
                  EXPENSES AND TAXES:**Fuel
              
              
              2,951
              
              
              11,916Purchased
                  power
              
              
              272,386
              
              
              246,590Nuclear
                  operating costs
              
              
              41,084
              
              
              95,653Other
                  operating costs
              
              
              90,810
              
              
              83,179Provision
                  for
                  depreciation
              
              
              18,016
              
              
              26,052Amortization
                  of regulatory assets
              
              
              53,861
              
              
              111,771Deferral
                  of
                  new regulatory assets
              
              
              (25,606
              )
              
              (24,795
              )General
                  taxes
              
              
              45,895
              
              
              48,078Income
                  taxes
              
              
              30,550
              
              
              54,972Total
                  operating expenses and taxes
              
              
              529,947
              
              
              653,416**OPERATING
                  INCOME**
              
              
              56,256
              
              
              72,942**OTHER
                  INCOME (net of income taxes)**
              
              
              25,470
              
              
              423**NET
                  INTEREST CHARGES:**Interest
                  on
                  long-term debt
              
              
              13,082
              
              
              15,609Allowance
                  for
                  borrowed funds used during construction and capitalized
                  interest
              
              
              (491
              )
              
              (2,235
              )Other
                  interest
                  expense
              
              
              5,149
              
              
              2,594Subsidiary's
                  preferred stock dividend requirements
              
              
              156
              
              
              640Net
                  interest
                  charges
              
              
              17,896
              
              
              16,608**NET
                  INCOME**
              
              
              63,830
              
              
              56,757**PREFERRED
                  STOCK DIVIDEND REQUIREMENTS**
              
              
              659
              
              
              659**EARNINGS
                  ON COMMON STOCK**
              
              $
              63,171
              
              $
              56,098**STATEMENTS
                  OF COMPREHENSIVE INCOME****NET
                  INCOME**
              
              $
              63,830
              
              $
              56,757**OTHER
                  COMPREHENSIVE INCOME (LOSS):**Unrealized
                  gain (loss) on available for sale securities
              
              
              5,735
              
              
              (2,717
              )Income
                  tax
                  expense (benefit) related to other comprehensive income
              
              
              2,069
              
              
              (1,124
              )Other
                  comprehensive income (loss), net of tax
              
              
              3,666
              
              
              (1,593
              )**TOTAL
                  COMPREHENSIVE INCOME**
              
              $
              67,496
              
              $
              55,164The
                  preceding
                  Notes to Consolidated Financial Statements as they relate to Ohio
                  Edison
                  Company are an integral partof
                  these
                  statements.
   59
  **OHIO
                    EDISON COMPANY****CONSOLIDATED
                    BALANCE SHEETS****(Unaudited)****March
                    31,**
                
                
                
                **December
                    31,****2006**
                
                
                
                **2005*****(In
                    thousands)*****ASSETS****UTILITY
                    PLANT:**In
                    service
                
                $
                2,552,488
                
                
                
                
                $
                2,526,851Less
                    -
                    Accumulated provision for depreciation
                
                
                996,292
                
                
                
                
                
                984,4631,556,196
                
                
                
                
                
                1,542,388Construction
                    work in progress
                
                
                56,728
                
                
                
                
                
                58,7851,612,924
                
                
                
                
                
                1,601,173**OTHER
                    PROPERTY AND INVESTMENTS:**Investment
                    in
                    lease obligation bonds
                
                
                325,519
                
                
                
                
                
                325,729Nuclear
                    plant
                    decommissioning trusts
                
                
                109,497
                
                
                
                
                
                103,854Long-term
                    notes receivable from associated companies
                
                
                1,758,377
                
                
                
                
                
                1,758,776Other
                
                
                43,491
                
                
                
                
                
                44,2102,236,884
                
                
                
                
                
                2,232,569**CURRENT
                    ASSETS:**Cash
                    and cash
                    equivalents
                
                
                1,048
                
                
                
                
                
                929Receivables-Customers
                    (less accumulated provisions of $8,136,000 and $7,619,000,
                    respectively,for
                    uncollectible accounts)
                
                
                251,937
                
                
                
                
                
                290,887Associated
                    companies
                
                
                104,839
                
                
                
                
                
                187,072Other
                    (less
                    accumulated provisions of $23,000 and $4,000,
                    respectively,for
                    uncollectible accounts)
                
                
                20,239
                
                
                
                
                
                15,327Notes
                    receivable from associated companies
                
                
                582,252
                
                
                
                
                
                536,629Prepayments
                    and other
                
                
                27,017
                
                
                
                
                
                93,129987,332
                
                
                
                
                
                1,123,973**DEFERRED
                    CHARGES AND OTHER ASSETS:**Regulatory
                    assets
                
                
                757,164
                
                
                
                
                
                774,983Prepaid
                    pension costs
                
                
                226,314
                
                
                
                
                
                224,813Property
                    taxes
                
                
                52,897
                
                
                
                
                
                52,875Unamortized
                    sale and leaseback costs
                
                
                53,888
                
                
                
                
                
                55,139Other
                
                
                29,013
                
                
                
                
                
                31,7521,119,276
                
                
                
                
                
                1,139,562$
                5,956,416
                
                
                
                
                $
                6,097,277**CAPITALIZATION
                    AND LIABILITIES****CAPITALIZATION:**Common
                    stockholder's equity-Common
                    stock,
                    without par value, authorized 175,000,000 shares - 100 shares
                    outstanding
                
                $
                2,297,289
                
                
                
                
                $
                2,297,253Accumulated
                    other comprehensive income
                
                
                7,760
                
                
                
                
                
                4,094Retained
                    earnings
                
                
                229,015
                
                
                
                
                
                200,844Total
                    common
                    stockholder's equity
                
                
                2,534,064
                
                
                
                
                
                2,502,191Preferred
                    stock not subject to mandatory redemption
                
                
                60,965
                
                
                
                
                
                60,965Preferred
                    stock of consolidated subsidiary not subject to mandatory
                    redemption
                
                
                14,105
                
                
                
                
                
                14,105Long-term
                    debt
                    and other long-term obligations
                
                
                931,507
                
                
                
                
                
                1,019,6423,540,641
                
                
                
                
                
                3,596,903**CURRENT
                    LIABILITIES:**Currently
                    payable long-term debt
                
                
                309,445
                
                
                
                
                
                280,255Short-term
                    borrowings-Associated
                    companies
                
                
                -
                
                
                
                
                
                57,715Other
                
                
                22,584
                
                
                
                
                
                143,585Accounts
                    payable-Associated
                    companies
                
                
                181,663
                
                
                
                
                
                172,511Other
                
                
                10,123
                
                
                
                
                
                9,607Accrued
                    taxes
                
                
                191,375
                
                
                
                
                
                163,870Accrued
                    interest
                
                
                12,054
                
                
                
                
                
                8,333Other
                
                
                95,273
                
                
                
                
                
                61,726822,517
                
                
                
                
                
                897,602**NONCURRENT
                    LIABILITIES:**Accumulated
                    deferred income taxes
                
                
                764,337
                
                
                
                
                
                769,031Accumulated
                    deferred investment tax credits
                
                
                23,194
                
                
                
                
                
                24,081Asset
                    retirement obligation
                
                
                84,282
                
                
                
                
                
                82,527Retirement
                    benefits
                
                
                292,965
                
                
                
                
                
                291,051Deferred
                    revenues - electric service programs
                
                
                113,930
                
                
                
                
                
                121,693Other
                
                
                314,550
                
                
                
                
                
                314,3891,593,258
                
                
                
                
                
                1,602,772**COMMITMENTS
                    AND CONTINGENCIES (Note 10)**$
                5,956,416
                
                
                
                
                $
                6,097,277The
                    preceding
                    Notes to Consolidated Financial Statements as they relate to
                    Ohio Edison
                    Company are an integral part of these balance sheets.
   60
  **OHIO
                      EDISON COMPANY****CONSOLIDATED
                      STATEMENTS OF CASH FLOWS****(Unaudited)****Three
                      Months Ended****March
                      31,****2006**
                  
                  
                  
                  **2005*****(In
                      thousands)*****CASH
                      FLOWS FROM OPERATING ACTIVITIES:**Net
                      income
                  
                  $
                  63,830
                  
                  
                  
                  
                  $
                  56,757Adjustments
                      to
                      reconcile net income to net cash from operating
                      activities-Provision
                      for
                      depreciation
                  
                  
                  18,016
                  
                  
                  
                  
                  
                  26,052Amortization
                      of regulatory assets
                  
                  
                  53,861
                  
                  
                  
                  
                  
                  111,771Deferral
                      of
                      new regulatory assets
                  
                  
                  (25,606
                  )
                  
                  
                  
                  
                  (24,795
                  )Nuclear
                      fuel
                      and lease amortization
                  
                  
                  532
                  
                  
                  
                  
                  
                  9,170Deferred
                      purchased power costs
                  
                  
                  (10,634
                  )
                  
                  
                  
                  
                  -Amortization
                      of lease costs
                  
                  
                  32,934
                  
                  
                  
                  
                  
                  33,030Deferred
                      income taxes and investment tax credits, net
                  
                  
                  (3,945
                  )
                  
                  
                  
                  
                  (24,627
                  )Accrued
                      compensation and retirement benefits
                  
                  
                  (1,494
                  )
                  
                  
                  
                  
                  (1,973
                  )Decrease
                      (increase) in operating assets-Receivables
                  
                  
                  116,271
                  
                  
                  
                  
                  
                  86,123Materials
                      and
                      supplies
                  
                  
                  -
                  
                  
                  
                  
                  
                  (15,834
                  )Prepayments
                      and other current assets
                  
                  
                  66,112
                  
                  
                  
                  
                  
                  (12,877
                  )Increase
                      (decrease) in operating liabilities-Accounts
                      payable
                  
                  
                  9,668
                  
                  
                  
                  
                  
                  (39,854
                  )Accrued
                      taxes
                  
                  
                  27,505
                  
                  
                  
                  
                  
                  44,448Accrued
                      interest
                  
                  
                  3,721
                  
                  
                  
                  
                  
                  6,993Electric
                      service prepayment programs
                  
                  
                  (7,763
                  )
                  
                  
                  
                  
                  -Other
                  
                  
                  3,922
                  
                  
                  
                  
                  
                  13,297Net
                      cash
                      provided from operating activities
                  
                  
                  346,930
                  
                  
                  
                  
                  
                  267,681**CASH
                      FLOWS FROM FINANCING ACTIVITIES:**New
                      Financing-Short-term
                      borrowings, net
                  
                  
                  -
                  
                  
                  
                  
                  
                  31,182Redemptions
                      and Repayments-Long-term
                      debt
                  
                  
                  (59,506
                  )
                  
                  
                  
                  
                  (15,787
                  )Short-term
                      borrowings, net
                  
                  
                  (178,716
                  )
                  
                  
                  
                  
                  -Dividend
                      Payments-Common
                      stock
                  
                  
                  (35,000
                  )
                  
                  
                  
                  
                  (47,000
                  )Preferred
                      stock
                  
                  
                  (659
                  )
                  
                  
                  
                  
                  (659
                  )Net
                      cash used
                      for financing activities
                  
                  
                  (273,881
                  )
                  
                  
                  
                  
                  (32,264
                  )**CASH
                      FLOWS FROM INVESTING ACTIVITIES:**Property
                      additions
                  
                  
                  (28,793
                  )
                  
                  
                  
                  
                  (79,783
                  )Proceeds
                      from
                      nuclear decommissioning trust fund sales
                  
                  
                  19,054
                  
                  
                  
                  
                  
                  68,400Investments
                      in
                      nuclear decommissioning trust funds
                  
                  
                  (19,054
                  )
                  
                  
                  
                  
                  (76,285
                  )Loans
                      to
                      associated companies, net
                  
                  
                  (45,224
                  )
                  
                  
                  
                  
                  (154,038
                  )Other
                  
                  
                  1,087
                  
                  
                  
                  
                  
                  6,263Net
                      cash used
                      for investing activities
                  
                  
                  (72,930
                  )
                  
                  
                  
                  
                  (235,443
                  )Net
                      increase
                      (decrease) in cash and cash equivalents
                  
                  
                  119
                  
                  
                  
                  
                  
                  (26
                  )Cash
                      and cash
                      equivalents at beginning of period
                  
                  
                  929
                  
                  
                  
                  
                  
                  1,230Cash
                      and cash
                      equivalents at end of period
                  
                  $
                  1,048
                  
                  
                  
                  
                  $
                  1,204The
                      preceding
                      Notes to Consolidated Financial Statements as they relate to
                      Ohio Edison
                      Company are an integral partof
                      these
                      statements.
  61
 
 ***Report
        of Independent Registered Public Accounting Firm***
 
 
 
 
 
 
 
 
 
 To
        the Stockholder
        and Board of
 Directors
        of Ohio
        Edison Company:
 
 We
        have reviewed the
        accompanying consolidated balance sheet of Ohio Edison Company and its
        subsidiaries as of March 31, 2006 and the related consolidated statements
        of income, comprehensive income and cash flows for each of the three-month
        periods ended March 31, 2006 and 2005. These interim financial statements
        are
        the responsibility of the Company’s management.
 
 We
        conducted our
        review in accordance with the standards of the Public Company Accounting
        Oversight Board (United States). A review of interim financial information
        consists principally of applying analytical procedures and making inquiries
        of
        persons responsible for financial and accounting matters. It is substantially
        less in scope than an audit conducted in accordance with the standards of
        the
        Public Company Accounting Oversight Board, the objective of which is the
        expression of an opinion regarding the financial statements taken as a whole.
        Accordingly, we do not express such an opinion.
 
 Based
        on our review,
        we are not aware of any material modifications that should be made to the
        accompanying consolidated interim financial statements for them to be in
        conformity with accounting principles generally accepted in the United States
        of
        America.
 
 We
        previously
        audited, in accordance with the standards of the Public Company Accounting
        Oversight Board (United States), the consolidated balance sheet as of December
        31, 2005, and the related consolidated statements of income, capitalization,
        common stockholder’s equity, preferred stock, cash flows and taxes for the year
        then ended (not presented herein), and in our report (which contained references
        to the Company’s change in its method of accounting for asset retirement
        obligations as of January 1, 2003 and conditional asset retirement obligations
        as of December 31, 2005 as discussed in Note 2(G) and Note 11 to those
        consolidated financial statements) dated February 27, 2006, we expressed an
        unqualified opinion on those consolidated financial statements. In our opinion,
        the information set forth in the accompanying consolidated balance sheet
        as of
        December 31, 2005, is fairly stated in all material respects in relation
        to the
        consolidated balance sheet from which it has been derived.
 
 
 
 
 PricewaterhouseCoopers
        LLP
 Cleveland,
        Ohio
 May
        8,
        2006
   62
  **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. Power supply requirements of the OE Companies
        are provided by FES - an affiliated
        company.
 
 **FirstEnergy
        Intra-System Generation Asset Transfers**
 
 On
        May 13,
        2005, Penn, and on May 18, 2005, the Ohio Companies, entered into certain
        agreements implementing a series of intra-system generation asset transfers
        that
        were completed in the fourth quarter of 2005. The asset transfers resulted
        in
        the respective undivided ownership interests of the Ohio Companies and Penn
        in
        FirstEnergy’s nuclear and non-nuclear generation assets being owned by NGC and
        FGCO, respectively. The generating plant interests transferred did not include
        OE's leasehold interests in certain of the plants that are currently subject
        to
        sale and leaseback arrangements with non-affiliates.
 
 On
        October 24,
        2005, the OE Companies completed the intra-system transfer of non-nuclear
        generation assets to FGCO. Prior to the transfer, FGCO, as lessee under a
        Master
        Facility Lease with the Ohio Companies and Penn, leased, operated and maintained
        the non-nuclear generation assets that it now owns. The asset transfers were
        consummated pursuant to FGCO's purchase option under the Master Facility
        Lease.
 
 On
        December 16,
        2005, the OE Companies completed the intra-system transfer of their ownership
        interests in the nuclear generation assets to NGC through an asset spin-off
        in
        the form of a dividend. FENOC continues to operate and maintain the nuclear
        generation assets.
 
 These
        transactions
        were undertaken pursuant to the Ohio Companies’ and Penn’s restructuring plans
        that were approved by the PUCO and the PPUC, respectively, under applicable
        Ohio
        and Pennsylvania electric utility restructuring legislation. Consistent with
        the
        restructuring plans, generation assets that had been owned by the Ohio Companies
        and Penn were required to be separated from the regulated delivery business
        of
        those companies through transfer to a separate corporate entity. The
        transactions essentially completed the divestitures contemplated by the
        restructuring plans by transferring the ownership interests to NGC and FGCO
        without impacting the operation of the plants.
 
 The
        transfers will
        affect the OE Companies' near-term results with reductions in both revenues
        and
        expenses. Revenues are reduced due to the termination of certain arrangements
        with FES, under which the OE Companies previously sold their nuclear-generated
        KWH to FES and leased their non-nuclear generation assets to FGCO, a subsidiary
        of FES. Their expenses are lower due to the nuclear fuel and operating costs
        assumed by NGC as well as depreciation and property tax expenses assumed
        by FGCO
        and NGC related to the transferred generating assets. With respect to OE's
        retained leasehold interests in the Perry Nuclear Power Plant and Beaver
        Valley
        Power Station Unit 2. OE has continued the nuclear-generated KWH sales
        arrangement with FES for the associated output and continues to be obligated
        on
        the applicable portion of expenses related to those interests. In addition,
        the
        OE Companies receive interest income on associated company notes receivable
        from the transfer of their generation net assets. FES will continue to provide
        the OE Companies’ PLR requirements under revised purchased power arrangements
        for the three-year period beginning January 1, 2006 (see Regulatory
        Matters).
  63
 
 The
        effects on the
        OE Companies' results of operations in the first quarter of 2006 compared
        to the
        first quarter of 2005 from the generation asset transfers (also reflecting
        OE's
        retained leasehold interests discussed above) are summarized in the following
        table:
 
 **Intra-System
                  Generation Asset Transfers -****First
                  Quarter 2006 vs First Quarter 2005 Income Statement
                  Effects*****Increase
                  (Decrease)***
              
              ***(In
                  millions)***Operating
                  Revenues:Non-nuclear
                  generating units rent
              
              $
              (45
              )
(a)Nuclear
                  generated KWH sales
              
              
              (64
              )
(b)Total
                  -
                  Operating Revenues Effect
              
              
              (109
              )Operating
                  Expenses and Taxes:Fuel
                  costs -
                  nuclear
              
              
              (9
              )
(c)Nuclear
                  operating costs
              
              
              (46
              )
(c)Provision
                  for
                  depreciation
              
              
              (17
              )
(d)General
                  taxes
              
              
              (3
              )
(e)Income
                  taxes
              
              
              (15
              )
(i)Total
                  -
                  Operating Expenses and Taxes Effect
              
              
              (90
              )Operating
                  Income Effect
              
              
              (19
              )Other
                  Income:Interest
                  income from notes receivable
              
              
              15
              (f)Nuclear
                  decommissioning trust earnings
              
              
              (2
              )
(g)Income
                  taxes
              
              
              (5
              )
(i)Total
                  - Other
                  Income Effect
              
              
              8Net
                  Interest
                  Charges:Allowance
                  for
                  funds used during construction
              
              
              (2
              )
(h)Total
                  - Net
                  Interest Charges Effect
              
              
              2Net
                  Income
                  Effect
              
              $
              (13
              )(a)
                  Elimination of non-nuclear generation assets lease to
                  FGCO.(b)
                  Reduction
                  of nuclear generated wholesale KWH sales to FES.(c)
                  Reduction
                  of nuclear fuel and operating costs.(d)
                  Reduction
                  of depreciation expense and asset retirement obligation accretion
                  related
                  togeneration
                  assets.(e)
                  Reduction
                  of property tax expense on generation assets.(f)
                  Interest
                  income on associated company notes receivable from thetransfer
                  of
                  generation net assets.(g)
                  Reduction
                  of earnings on nuclear decommissioning trusts.(h)
                  Reduction
                  of allowance for borrowed funds used during construction on nuclear
                  capital expenditures.(i)
                  Income tax
                  effect of the above adjustments.
 
 **Results
        of Operations**
  Earnings on common stock in the first quarter of 2006 increased to $63 million
        from $56 million in the first quarter of 2005. The increase in earnings in
        2006 primarily resulted from reduced operating expenses and taxes and increased
        other income, partially offset by lower operating revenues and increased
        net
        interest charges principally from the asset transfer effects shown in the
        table
        above.
 
 *Operating
        Revenues*
 
 Operating revenues decreased by $140 million or 19.3% in the first quarter
        of
        2006 compared with the same period in 2005, primarily due to the generation
        asset transfer impact summarized in the table above. Excluding the effects
        of
        the asset transfer, operating revenues decreased $31 million, primarily due
        to
        decreases of $59 million and $98 million in wholesale sales and
        distribution revenues, respectively, partially offset by increases in retail
        generation revenues of $108 million and reduced customer shopping
        incentives of $18 million.
 
 The lower wholesale revenues reflected the termination of a non-affiliated
        wholesale sales agreement and the cessation of the MSG sales arrangements
        under
        OE’s transition plan in December 2005. OE had been required to provide the MSG
        to non-affiliated alternative suppliers.
 
 Increased retail generation revenues in all customer sectors (residential
        -
        $43 million; commercial - $32 million; and industrial - $33 million)
        reflected the impact of higher KWH sales and higher unit prices. The increase
        in
        generation KWH sales primarily resulted from decreased customer shopping,
        as the
        percentage of generation services provided by alternative suppliers to total
        sales delivered in OE's service area decreased by the following percentages:
        residential - 8.8%; commercial - 11.0%; and industrial - 9.3%. The decreased
        shopping resulted from alternative energy suppliers terminating their supply
        arrangements with OE’s shopping customers in the fourth quarter of 2005. Higher
        unit prices reflected the Rate Stabilization Charge and fuel recovery rider
        that
        became effective in January 2006 under the RCP.
  64
 Revenues from distribution throughput decreased $98 million in the first
        quarter
        of 2006 compared with the same period in 2006. The decrease in all customer
        sectors (residential - $40 million; commercial - $32 million; and
        industrial - $26 million) primarily reflected the impact of lower composite
        prices and reduced KWH deliveries. The lower unit prices reflected the
        completion of the generation-related transition cost recovery under OE’s and
        Penn’s respective rate restructuring plans in 2005, partially offset by the
        recovery of MISO costs beginning in 2006 (see Outlook -- Regulatory Matters).
        Lower distribution KWH deliveries to residential and commercial customers
        reflected the impact of milder weather conditions in the first quarter of
        2006,
        compared to the same period of 2005.
 
 Under the Ohio transition plan, OE had provided incentives to customers to
        encourage switching to alternative energy providers, which reduced OE’s revenues
        by $18 million in the first quarter of 2005. These revenue reductions, which
        were deferred for future recovery and did not affect current period earnings,
        ceased in 2006. The deferred shopping incentives (Extended RTC) are now being
        recovered under the RCP (see Regulatory Matters below.)
 
 Changes in electric generation sales and distribution deliveries in the first
        quarter of 2006 from the same quarter of 2005 are summarized in the following
        table:
 
 **Changes
                  in KWH Sales****Increase
                  (Decrease)**Electric
                  Generation:Retail
              
              
              11.3
              %Wholesale
                  -
                  Non-Associated
              
              
              (95.6
              )%Wholesale
                  -
                  Associated (FES)*
              
              
              (75.7
              )%**Total
                  Electric Generation Sales**
              
              
              (28.0
              )%Distribution
                  Deliveries:Residential
              
              
              (1.8
              )%Commercial
              
              
              (1.0
              )%Industrial
              
              
              (1.7
              )%**Total
                  Distribution Deliveries**
              
              
              (1.5
              )%*****Change
                  reflects impact of generation asset transfers.
 
 *Operating
        Expenses and Taxes*
 
 Total operating expenses and taxes decreased by $123 million in the first
        quarter of 2006 from the first quarter of 2005 principally due to the effects
        of
        the generation asset transfer shown in the table above. Excluding the asset
        transfer effects, the following table presents changes from the prior year
        by
        expense category.
 
 **Operating
                  Expenses and Taxes - Changes****Increase
                  (Decrease)**
              
              ***(In
                  millions)***Purchased
                  power costs
              
              $
              26Nuclear
                  operating costs
              
              
              (8
              )Other
                  operating costs
              
              
              7Provision
                  for
                  depreciation
              
              
              9Amortization
                  of regulatory assets
              
              
              (58
              )Deferral
                  of
                  new regulatory assets
              
              
              (1
              )General
                  taxes
              
              
              1Income
                  taxes
              
              
              (10
              )**Total
                  operating expenses and taxes**
              
              $
              (34
              )
 
 I ncreased
        purchased
        power costs in the first quarter of 2006 reflected higher unit prices associated
        with the new power supply agreement with FES, partially offset by a decrease
        in
        KWH purchased to meet the lower net generation sales requirements, and RCP
        fuel
        deferrals of $11 million. Under the RCP that was effective January 1, 2006,
        OE can defer increased fuel costs (i.e., in excess of 2002 baseline amounts)
        above the amount collected through the fuel recovery mechanism. Excluding
        the
        effects of the generation asset transfers, the lower nuclear operating costs
        for
        OE’s nuclear leasehold interests were primarily due to the absence in 2006 of
        the Perry Nuclear Power Plant scheduled refueling outage (including an unplanned
        extension) in the first quarter of 2005. The increase in other operating
        costs
        was primarily from increased transmission expenses related to MISO Day 2
        operations that began on April 1, 2005.
  65
 
 Excluding the effects of the generation asset transfers, higher depreciation
        expense in the first quarter of 2006 compared with the same quarter of 2005
        reflects capital additions subsequent to the first quarter of 2005. Lower
        amortization of regulatory assets was due to the completion of the
        generation-related transition cost amortization under OE's and Penn's respective
        transition plans, partially offset by the amortization of deferred MISO costs
        being recovered in 2006. The higher deferrals of new regulatory assets primarily
        resulted from the deferral of distribution costs and related interest
        ($19 million) under the RCP, partially offset by the decrease in shopping
        incentive deferrals ($18 million) which ceased in 2006 under the Ohio
        transition plan. The deferral of interest on the unamortized shopping incentive
        balances will continue under the RCP.
 
 *Other
        Income*
 
 Other income increased $25 million in the first quarter of 2006 compared
        with
        the same quarter of 2005, partially due to the effects of the asset transfer.
        Excluding the asset transfer effects, the $17 million increase is primarily
        due
        to the absence in 2006 of the 2005 accruals of an $8.5 million civil penalty
        payable to the DOJ and $10 million for environmental projects in connection
        with the Sammis New Source Review settlement (see Outlook - Environmental
        Matters).
 
 *Net
        Interest
        Charges*
 
 Net interest charges increased $1 million in the first quarter of 2006 compared
        to the same period of 2005 primarily due to the effects of the generation
        asset
        transfer. Excluding the asset transfer, interest charges continued to trend
        lower, decreasing by $1 million in the first quarter of 2006 compared with
        the
        same quarter of 2005.
 
 **Capital
        Resources and Liquidity**
 
 OE’s cash requirements in 2006 for operating expenses, construction
        expenditures, scheduled debt maturities and preferred stock redemptions are
        expected to be met with cash from operations and short-term credit arrangements.
        Available borrowing capacity under credit facilities will be used to manage
        working capital requirements.
 
 In connection with a plan to realign its capital structure, OE may also issue
        up
        to $600 million of long-term debt in 2006 with proceeds expected to fund
        a
        return of equity capital to FirstEnergy.
 
 *Changes
        in Cash
        Position*
 
 OE's cash and cash equivalents were approximately $1 million as of March
        31,
        2006 and December 31, 2005.
 
 *Cash
        Flows From
        Operating Activities*
 
 Cash provided from operating activities during the first quarter of 2006,
        compared with the first quarter of 2005, were as follows:
 
 **Three
                  Months Ended March 31,****Operating
                  Cash Flows**
              
              **2006**
              
              **2005*****(In
                  millions)***Cash
                  earnings
                  (1)
              
              $
              120
              
              $
              185Working
                  capital and other
              
              
              227
              
              
              83Net
                  cash
                  provided from operating activities
              
              $
              347
              
              $
              268
 
 (1) Cash
        earnings are a non-GAAP measure (see reconciliation below).
  66
  Cash earnings (in the table above) are not a measure of performance
        calculated in accordance with GAAP. OE believes that cash earnings are 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 March 31,****Reconciliation
                  of Cash Earnings**
              
              **2006**
              
              **2005*****(In
                  millions)***Net
                  Income
                  (GAAP)
              
              $
              64
              
              $
              57Non-Cash
                  Charges (Credits):Provision
                  for
                  depreciation
              
              
              18
              
              
              26Amortization
                  of regulatory assets
              
              
              54
              
              
              112Deferral
                  of
                  new regulatory assets
              
              
              (26
              )
              
              (25
              )Nuclear
                  fuel
                  and lease amortization
              
              
              1
              
              
              9Amortization
                  of electric service obligation
              
              
              (8
              )
              
              -Amortization
                  of lease costs
              
              
              33
              
              
              33Deferred
                  income taxes and investment tax credits, net
              
              
              (4
              )
              
              (25
              )Deferred
                  purchased power costs
              
              
              (11
              )
              
              -Accrued
                  compensation and retirement benefits
              
              
              (1
              )
              
              (2
              )Cash
                  earnings
                  (Non-GAAP)
              
              $
              120
              
              $
              185
 
 Net cash provided from operating activities increased $79 million in the
        first
        quarter of 2006, compared with the first quarter of 2005, due to a $144 million
        increase from changes in working capital, partially offset by a $65 million
        decrease in cash earnings as described above under “Results from Operations.”
The increase in working capital primarily reflects changes in accounts payable
        and receivables of $80 million and prepayments and other current assets of
        $79 million, partially offset by changes in accrued taxes of
        $17 million.
 
 *Cash
        Flows From
        Financing Activities*
  Net cash used for financing activities increased to $274 million in the first
        quarter of 2006 from $32 million in the first quarter of 2005. The increase
        primarily reflected repayments of short-term borrowings to associated companies,
        partially offset by a $12 million decrease in common stock dividend
        payments to FirstEnergy.
 
 OE had approximately $583 million of cash and temporary cash investments
        (which include short-term notes receivable from associated companies) and
        $23 million of short-term indebtedness as of March 31, 2006. OE has
        authorization from the PUCO to incur short-term debt of up to $500 million,
        which is expected to come from the bank facility and the utility money pool
        described below. Penn has authorization from the SEC, continued by FERC rules
        adopted as a result of EPACT's repeal of PUHCA, to incur short-term debt
        up to
        its charter limit of $43 million as of March 31, 2006, and will have
        access to the bank facility and the utility money pool.
 
 OES Capital is a wholly owned subsidiary of OE whose borrowings are secured
        by
        customer accounts receivable purchased from OE. OES Capital can borrow up
        to
        $170 million under a receivables financing arrangement. As a separate legal
        entity with separate creditors, OES Capital would have to satisfy its
        obligations to creditors before any of its remaining assets could be made
        available to OE. As of March 31, 2006, the facility was not drawn.
 
 Penn Power Funding LLC (Penn Funding), a wholly owned subsidiary of Penn,
        is a
        limited liability company whose borrowings are secured by customer accounts
        receivable purchased from Penn. Penn Funding can borrow up to the full amount
        of
        $25 million available as of March 31, 2006 under a receivables
        financing arrangement which expires June 29,
        2006 .
        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 March 31,
        2006, the facility was drawn for $19 million.
 
 As of March 31, 2006, OE and Penn had the aggregate capability to issue
        approximately $502 million of additional FMB on the basis of property
        additions and retired bonds under the terms of their respective mortgage
        indentures. The issuance of FMB by OE is also subject to provisions of its
        senior note indenture generally limiting the incurrence of additional secured
        debt, subject to certain exceptions that would permit, among other things,
        the
        issuance of secured debt (including FMB) (i) supporting pollution control
        notes
        or similar obligations, or (ii) as an extension, renewal or replacement of
        previously outstanding secured debt. In addition, OE is permitted under the
        indenture to incur additional secured debt not otherwise permitted by a
        specified exception of up to $644 million as of March 31, 2006. Based upon
        applicable earnings coverage tests in their respective charters, OE and Penn
        could issue a total of $3.1 billion of preferred stock (assuming no
        additional debt was issued) as of March 31, 2006.
  67
 
 As of April 26, 2006, a shelf registration statement filed by OE became
        effective and provides, together with previously effective OE registration
        statements, $1 billion of capacity to support future issuances of debt
        securities by OE.
 
 FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as
        Borrowers, have entered into a syndicated $2 billion five-year revolving
        credit facility with a syndicate of banks that expires in June 2010. 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 borrowing limit under the facility
        is
        $500 million and Penn’s is $50 million, subject in each case to
        applicable regulatory approvals.
 
 Under the revolving credit facility, borrowers may request the issuance of
        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 $726 million as of
        March 31, 2006.
 
 The revolving credit facility contains financial covenants requiring each
        borrower to maintain a consolidated debt to total capitalization ratio of
        no
        more than 65%. As of March 31, 2006, debt to total capitalization as defined
        under the revolving credit facility was 33% for OE and 35% for
        Penn.
 
 The facility does not contain any provisions that either restrict the ability
        of
        OE and Penn to borrow or accelerate repayment of outstanding advances as
        a
        result of any change in credit ratings. Pricing is defined in “pricing grids”,
        whereby the cost of funds borrowed under the facility is related to OE’s and
        Penn’s credit ratings.
 
 OE and Penn have the ability to borrow from their regulated affiliates and
        FirstEnergy to meet their short-term working capital requirements. FESC
        administers this money pool and tracks surplus funds of FirstEnergy and its
        regulated subsidiaries. Companies receiving a loan under the money pool
        agreements must repay the principal amount, together with accrued interest,
        within 364 days of borrowing the funds. The rate of interest is the same
        for
        each company receiving a loan from the pool and is based on the average cost
        of
        funds available through the pool. The average interest rate for borrowings
        in
        the first quarter of 2006 was 4.58%.
 
 OE’s
        access to the
        capital markets and the costs of financing are influenced by the ratings
        of its
        securities. The ratings outlook from S&P on all securities is stable. The
        ratings outlook from Moody's and Fitch on all securities is
        positive.
  In
        April 2006,
        pollution control notes that were formerly obligations of OE and Penn were
        refinanced and became obligations of FGCO and NGC. The
        proceeds from
        the refinancings were used to repay a portion of their associated company
        notes
        payable to Penn and OE. With those repayments, OE redeemed $74.8 million
        and Penn redeemed $6.95 million of pollution control notes having variable
        interest rates.
 
 *Cash
        Flows From
        Investing Activities*
  Net cash used for investing activities decreased to $73 million in the first
        quarter of 2006 from $235 million in the first quarter of 2005. The
        decrease resulted primarily from a $109 million decrease in loans to associated
        companies and a $51 million decrease in property additions, which reflects
        the impact of the generation asset transfers.
 
 During the remaining three quarters of 2006, capital requirements for property
        additions and capital leases are expected to be approximately $93 million.
        OE
        has additional requirements of approximately $4 million to meet requirements
        for
        maturing long-term debt during the remainder of 2006. These cash requirements
        are expected to be satisfied from a combination of internal cash, funds raised
        in the long-term debt capital markets and short-term credit arrangements. OE’s
        capital spending for the period 2006-2010 is expected to be about
        $638 million, of which approximately $122 million applies to 2006.
 
 **Off-Balance
        Sheet Arrangements**
 
 Obligations not included on OE’s Consolidated Balance Sheets primarily consist
        of sale and leaseback arrangements involving Perry Unit 1 and Beaver Valley
        Unit
        2. The present value of these operating lease commitments, net of trust
        investments, was $666 million as of March 31, 2006.
  68
  **Equity
        Price Risk**
  Included in OE’s nuclear decommissioning trust investments are marketable equity
        securities carried at their market value of approximately $71 million and
        $67
        million as of March 31, 2006 and December 31, 2005, respectively. A
        hypothetical 10% decrease in prices quoted by stock exchanges would result
        in a
        $7 million reduction in fair value as of March 31, 2006. Changes in the
        fair value of these investments are recorded in OCI unless recognized as
        a
        result of a sale or recognized as regulatory assets or liabilities.
 
 **Outlook**
  The electric industry continues to transition to a more competitive environment
        and all of the OE Companies’ customers can select alternative energy suppliers.
        The OE Companies continue to deliver power to residential homes and businesses
        through their existing distribution system, which remains regulated. Customer
        rates have been restructured into separate components to support customer
        choice. In Ohio and Pennsylvania, the OE Companies have a continuing
        responsibility to provide power to those customers not choosing to receive
        power
        from an alternative energy supplier subject to certain limits.
 
 *Regulatory
        Matters*
 
 Regulatory
        assets
        are costs which have been authorized by the PUCO, the PPUC and the FERC for
        recovery from customers in future periods or for which authorization is
        probable. Without the probability of such authorization, costs currently
        recorded as regulatory assets would have been charged to income as incurred.
        All
        regulatory assets are expected to be recovered under the provisions of the
        OE
        Companies’ transition plans and rate restructuring plans. OE‘s regulatory assets
        were $757 million and $775 million as of March 31, 2006 and
        December 31, 2005, respectively. Penn had net regulatory liabilities of
        $64 million and $59 million as of March 31, 2006 and
        December 31, 2005, respectively, which are included in Other Noncurrent
        Liabilities on the Consolidated Balance Sheets as of March 31, 2006 and
        December 31, 2005.
 
 On October 21, 2003 the Ohio Companies filed the RSP case with the PUCO.
        On
        August 5, 2004, the Ohio Companies accepted the RSP as modified and approved
        by
        the PUCO in an August 4, 2004 Entry on Rehearing, subject to a CBP. The RSP
        was
        intended to establish generation service rates beginning January 1, 2006,
        in
        response to 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 arguments on the appeals. On May 3, 2006, the Supreme Court
        of
        Ohio issued an opinion affirming that order with respect to the approval
        of the
        rate stabilization charge, approval of the shopping credits, the grant of
        interest on shopping credit incentive deferral amounts, and approval of
        FirstEnergy’s financial separation plan. It remanded the approval of the RSP
        pricing back to the PUCO for further consideration of the issue as to whether
        the RSP, as adopted by the PUCO, provided for sufficient customer participation
        in the competitive marketplace.
 
 Under provisions of the RSP, the PUCO had required the Ohio Companies to
        undertake a CBP to secure generation and allow for customer pricing
        participation in the competitive marketplace. Any acceptance of future
        competitive bid results would terminate the RSP pricing, with no accounting
        impacts to the RSP, and not until 12 months after the PUCO authorizes such
        termination. On December 9, 2004, the PUCO rejected the auction price
        results from the CBP for the generation supply period beginning January 1,
        2006
        and issued an entry stating that the pricing under the approved revised RSP
        would take effect on January 1, 2006. On February 23, 2006 the CBP
        auction manager, National Economic Research Associates, notified the PUCO
        that a
        subsequent CBP to potentially provide firm generation service for the Ohio
        Companies' 2007 and 2008 actual load requirements could not proceed due to
        lack
        of interest, as there were no bidder applications submitted. Additionally,
        on
        March 20, 2006, the PUCO denied applications for rehearing filed by various
        parties regarding the PUCO's rules for the CBP. The above May 3, 2006
        Supreme Court of Ohio opinion may require the PUCO to reconsider this customer
        pricing process.
 
 On
        January 4, 2006,
        the PUCO approved, with modifications, OE's RCP to supplement the RSP to
        provide customers with more certain rate levels than otherwise available
        under
        the RSP during the plan period. Major provisions of the RCP
        include:
 
 ·
              Maintaining
                  the existing level of base distribution rates through December 31,
                  2008 for OE;
 
 ·
              Deferring
                  and
                  capitalizing for future recovery (over a 25-year period) with carrying
                  charges certain distribution costs to be incurred by all of the
                  Ohio
                  Companies during the period January 1, 2006 through December 31,
                  2008, not to exceed $150 million in each of the three
                  years;
  69
  
 ·
              Adjusting
                  the
                  RTC and extended RTC recovery periods and rate levels so that full
                  recovery of authorized costs will occur as of December 31, 2008 for
                  OE;
 
 ·
              Reducing
                  the
                  deferred shopping incentive 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
 
 ·
              Recovering
                  increased fuel costs (compared to a 2002 baseline) of up to $75
                  million,
                  $77 million, and $79 million, in 2006, 2007, and 2008,
                  respectively, from all OE and TE distribution and transmission
                  customers
                  through a fuel recovery mechanism. The Ohio Companies may defer
                  and
                  capitalize (for recovery over a 25-year period) increased fuel
                  costs above
                  the amount collected through the fuel recovery mechanism (in lieu
                  of
                  implementation of the GCAF rider).
 
 The
        following table
        provides OE’s estimated amortization of regulatory transition costs and deferred
        shopping incentives (including associated carrying charges) under the RCP
        for
        the period 2006 through 2008:
 
 **Amortization****Period**
              
              
              **Amortization****(In
                  millions)**2006
              
              $
              1722007
              
              
              1802008
              
              
              206**Total
                  Amortization**
              
              **$**
              **558**
 
 The
        PUCO’s January
        4, 2006 approval of the RCP also included approval of the Ohio
        Companies’ supplemental
        stipulation which was filed with the PUCO on November 4, 2005 and which was
        an
        additional component of the RCP filed on September 9, 2005. On
        January 10, 2006, the Ohio Companies filed a Motion for Clarification of
        the PUCO order approving the RCP. The Ohio Companies sought clarity on issues
        related to distribution deferrals, including requirements of the review process,
        timing for recognizing certain deferrals and definitions of the types of
        qualified expenditures. The Ohio Companies also sought confirmation that
        the
        list of deferrable distribution expenditures originally included in the revised
        stipulation fall within the PUCO order definition of qualified expenditures.
        On
        January 25, 2006, the PUCO issued an Entry on Rehearing granting in part,
        and denying in part, the Ohio Companies’ previous requests and clarifying issues
        referred to above. The PUCO granted the Ohio Companies’ requests to:
  ·
                Recognize fuel and distribution deferrals commencing January 1,
                    2006;·
                Recognize distribution deferrals on a monthly basis prior to
                    review by the
                    PUCO Staff;·
                Clarify that the types of distribution expenditures included
                    in the
                    Supplemental Stipulation may be deferred; and·
                Clarify that distribution expenditures do not have to be “accelerated” in
                    order to be deferred.
  The
        PUCO approved
        the Ohio Companies’ methodology for determining distribution deferral amounts,
        but denied the Motion in that the PUCO Staff must verify the level of
        distribution expenditures contained in current rates, as opposed to simply
        accepting the amounts contained in the Ohio Companies’ Motion. On February 3,
        2006, several other parties filed applications for rehearing on the PUCO's
        January 4, 2006 Order. The Ohio Companies responded to the applications for
        rehearing on February 13, 2006. In an Entry on Rehearing issued by the PUCO
        on March 1, 2006, all motions for rehearing were denied. Certain of these
        parties have subsequently filed their notices of appeal with the Supreme
        Court
        of Ohio alleging various errors made by the PUCO in its order approving the
        RCP.
 
 On
        December 30,
        2004, OE filed with the PUCO two applications related to the recovery of
        transmission and ancillary service related costs. The first application sought
        recovery of these costs beginning January 1, 2006. OE requested that these
        costs be recovered through a rider that would be effective on January 1,
        2006 and adjusted each July 1 thereafter. The parties reached a settlement
        agreement that was approved by the PUCO on August 31, 2005. The incremental
        transmission and ancillary service revenues expected to be recovered from
        January through June 30, 2006 are approximately $34 million. This
        amount includes the recovery of the 2005 deferred MISO expenses as described
        below. On May 1, 2006, OE filed a modification to the rider to 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 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 30, 2004 was denied. The PUCO also authorized OE to accrue
        carrying charges on the deferred balances. On August 31, 2005, the OCC
        appealed the PUCO's decision. All briefs have been filed. On March 20, 2006,
        the
        Ohio Supreme Court, on its own motion, consolidated the OCC's appeal of OE's
        case with a similar case involving Dayton Power & Light Company. Oral
        argument is currently scheduled for May 10, 2006.
   70
  On
        January 20,
        2006, the OCC sought rehearing of the PUCO approval of the recovery of deferred
        costs through the rider during the period January 1, 2006 through June 30,
        2006. The PUCO denied the OCC's application on February 6, 2006. On March
        23, 2006, the OCC appealed the PUCO's order to the Ohio Supreme Court. The
        OCC's
        brief is expected to be filed during the second quarter of 2006. The briefs
        of the PUCO and OE will be due within thirty days of the OCC's filing. On
        March
        27, 2006, the OCC filed a motion to consolidate this appeal with the deferral
        appeals discussed above and to postpone oral arguments in the deferral appeal
        until after all briefs are filed in this most recent appeal of the rider
        recovery mechanism. On
        April 18, 2006,
        the Court denied both parts of the motion but on its own motion consolidated
        the
        OCC's appeal of OE's case with a similar case of Dayton Power & Light
        Company and stayed briefing on these appeals.
 
 On
        October 11,
        2005, Penn filed a plan with the PPUC to secure electricity supply for its
        customers at set rates following the end of its transition period on
        December 31, 2006. Penn recommended that the RFP process cover the period
        January 1, 2007 through May 31, 2008. Hearings were held on
        January 10, 2006 with main briefs filed on January 27, 2006 and reply
        briefs filed on February 3, 2006. On February 16, 2006, the ALJ issued a
        Recommended Decision to adopt Penn's RFP process with modifications. The
        PPUC
        approved the Recommended Decision with additional modifications on
        April 20, 2006. The approved plan is designed to provide customers with PLR
        service for 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.
 
 On
        November 1, 2005,
        FES filed two power sales agreements for approval with the FERC. One power
        sales
        agreement provided for FES to provide the PLR requirements of the Ohio Companies
        at a price equal to the retail generation rates approved by the PUCO for
        a
        period of three years beginning January 1, 2006. The Ohio Companies will be
        relieved of their obligation to obtain PLR power requirements from FES if
        the
        Ohio competitive bid process results in a lower price for retail customers.
        A
        similar power sales agreement between FES and Penn permits Penn to obtain
        its
        PLR power requirements from FES at a fixed price equal to the retail generation
        price during 2006. The PPUC approved Penn's plan with modifications on April
        20,
        2006 to use an RFP process to obtain its power supply requirements after
        2006.
 
 On
        December 29,
        2005, the FERC issued an order setting the two power sales agreements for
        hearing. The order criticized the Ohio competitive bid process, and required
        FES
        to submit additional evidence in support of the reasonableness of the prices
        charged in the power sales agreements. A pre-hearing conference was held
        on
        January 18, 2006 to determine the hearing schedule in this case. FES
        expects an initial decision to be issued in this case in late January 2007,
        as a
        result of the April 20, 2006 extension of the procedural schedule. The outcome
        of this proceeding cannot be predicted. FES has sought rehearing of the
        December 29, 2005 order and the FERC granted rehearing for future
        consideration on March 1, 2006.
 
 See
        Note 11 to
        the consolidated financial statements for further details and a complete
        discussion of regulatory matters in Ohio and Pennsylvania and a detailed
        discussion of reliability initiatives, including initiatives by the PPUC,
        that
        impact Penn.
 
 *Environmental
        Matters*
 
 OE
        accrues
        environmental liabilities when it concludes that it is probable that it has
        an
        obligation for such costs and can reasonably estimate the amount of such
        costs.
        Unasserted claims are reflected in OE’s determination of environmental
        liabilities and are accrued in the period that they are both probable and
        reasonably estimable.
 
 *W.
        H. Sammis
        Plant*
 
 In
        1999 and 2000,
        the EPA issued NOV or Compliance Orders to nine utilities alleging violations
        of
        the Clean Air Act based on operation and maintenance of 44 power plants,
        including the W. H. Sammis Plant, which was owned at that time by OE and
        Penn.
        In addition, the DOJ filed eight civil complaints against various investor-owned
        utilities, including a complaint against OE and Penn in the U.S. District
        Court
        for the Southern District of Ohio. These cases are referred to as New Source
        Review cases. On March 18, 2005, OE and Penn announced that they had
        reached a settlement with the EPA, the DOJ and three states (Connecticut,
        New
        Jersey, and New York) that resolved all issues related to the W. H. Sammis
        Plant
        New Source Review litigation. This settlement agreement was approved by the
        Court on July 11, 2005, and requires reductions of NO X and SO 2 emissions at the
        W. H. Sammis Plant and other coal fired plants through the installation of
        pollution control devices and provides for stipulated penalties for failure
        to
        install and operate such pollution controls in accordance with that agreement.
        Consequently, if OE and Penn fail to install such pollution control devices,
        for
        any reason, including, but not limited to, the failure of any third-party
        contractor to timely meet its delivery obligations for such devices, OE and
        Penn
        could be exposed to penalties under the settlement agreement. 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). On 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 paid by OE and Penn of $7.8 million
        and $0.7 million, respectively. OE and Penn also recognized liabilities in
        the first quarter of 2005 of $9.2 million and $0.8 million,
        respectively, for probable future cash contributions toward environmentally
        beneficial projects.
  71
  See
        Note 10(B) to
        the consolidated financial statements for further details and a complete
        discussion of environmental matters.
 
 *Other
        Legal
        Proceedings*
 
 There are various lawsuits, claims (including claims for asbestos exposure)
        and
        proceedings related to OE’s normal business operations pending against OE and
        its subsidiaries. The other potentially material items not otherwise discussed
        above are described below.
 
 *Power
        Outages
        and Related Litigation-*
 
 On
        August 14,
        2003, various states and parts of southern Canada experienced widespread
        power
        outages. The outages affected approximately 1.4 million customers in
        FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s
        final report in April 2004 on the outages concluded, among other things,
        that
        the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically,
        the
        final report concluded, among other things, that the initiation of the
        August 14, 2003 power outages resulted from an alleged failure of both
        FirstEnergy and ECAR to assess and understand perceived inadequacies within
        the
        FirstEnergy system; inadequate situational awareness of the developing
        conditions; and a perceived failure to adequately manage tree growth in certain
        transmission rights of way. The Task Force also concluded that there was
        a
        failure of the interconnected grid's reliability organizations (MISO and
        PJM) to
        provide effective real-time diagnostic support. The final report is publicly
        available through the Department of Energy’s 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
        March 31, 2006 for any expenditure 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 Company, Inc. as well) for claims paid to insureds
        for
        damages allegedly arising as a result of the loss of power on August 14,
        2003. The listed insureds in these cases, in many instances, are not customers
        of any FirstEnergy company. The fourth case involves the claim of a non-customer
        seeking reimbursement for losses incurred when its store was burglarized
        on
        August 14, 2003. On
        March 7, 2006,
        the PUCO issued a ruling applicable to all pending cases. Among its various
        rulings, the PUCO consolidated all of the pending outage cases for hearing;
        limited the litigation to service-related claims by customers of the Ohio
        operating companies; dismissed FirstEnergy Corp. as a defendant; ruled that
        the
        U.S.-Canada Power System Outage Task Force Report was not admissible into
        evidence; and gave the plaintiffs additional time to amend their complaints
        to
        otherwise comply with the PUCO’s underlying order. The plaintiffs in
        one case have since filed an amended complaint. The named FirstEnergy companies
        have answered and also have filed a motion to dismiss the action, which is
        pending. Also, most complainants, along with the FirstEnergy companies, filed
        applications for rehearing with the PUCO over various rulings contained in
        the
        March 7, 2006 order. On April 26, 2006, the PUCO granted rehearing to allow
        the
        insurance company claimants, as insurers, to prosecute their claims in their
        name so long as they also identify the underlying insured entities and the
        Ohio
        utilities which provide their service. The PUCO denied all other motions
        for
        rehearing. No estimate of potential liability is available for any of these
        cases. 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.
        Following the PUCO's March 7, 2006 order, that action was voluntarily
        dismissed by the claimants.
  72
  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 and results of operations.
 
 *Nuclear
        Plant
        Matters-*
 
 As
        of
        December 16, 2005, NGC acquired ownership of the nuclear generation assets
        transferred from OE, Penn, CEI and TE with the exception of leasehold interests
        of OE and TE in certain of the nuclear plants that are subject to sale and
        leaseback arrangements with non-affiliates. Excluding OE's retained
        leasehold interests in Beaver Valley Unit 2 (21.66%) and Perry (12.58%),
        the transfer included the OE Companies’ prior owned interests in Beaver Valley
        Unit 1 (100%), Beaver Valley Unit 2 (33.96%) and Perry
        (22.66%).
 
 On
        August 12,
        2004, the NRC notified FENOC that it would increase its regulatory oversight
        of
        the Perry Nuclear Power Plant as a result of problems with safety system
        equipment over the preceding two years and the licensee's failure to take
        prompt
        and corrective action. FENOC operates the Perry Nuclear Power Plant.
 
 On
        April 4,
        2005, the NRC held a public meeting to discuss FENOC’s performance at the Perry
        Nuclear Power Plant as identified in the NRC's annual assessment letter to
        FENOC. Similar public meetings are held with all nuclear power plant licensees
        following issuance by the NRC of their annual assessments. According to the
        NRC,
        overall the Perry 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. By an inspection report dated January 18, 2006, the NRC closed one
        of the White Findings (related to emergency preparedness) which led to the
        multiple degraded cornerstones.
 
 On
        September 28,
        2005, the NRC sent a CAL to FENOC describing commitments that FENOC had made
        to
        improve the performance at the Perry Plant and stated that the CAL would
        remain
        open until substantial improvement was demonstrated. The CAL was anticipated
        as
        part of the NRC's Reactor Oversight Process. In the NRC's 2005 annual assessment
        letter dated March 2, 2006 and associated meetings to discuss the performance
        of
        Perry on March 14, 2006, the NRC again stated that the Perry Plant
        continued to operate in a manner that "preserved public health and safety."
        However, the NRC also stated that increased levels of regulatory oversight
        would
        continue until sustained improvement in the performance of the facility was
        realized. If performance does not improve, the NRC has a range of options
        under
        the Reactor Oversight Process, from increased oversight to possible impact
        to
        the plant’s operating authority. Although FirstEnergy is unable to predict the
        impact of the ultimate disposition of this matter, it could have a material
        adverse effect on FirstEnergy's or its subsidiaries' financial condition,
        results of operations and cash flows.
 
 *Other
        Legal
        Matters-*
 
 On
        October 20,
        2004, FirstEnergy was notified by the SEC that the previously disclosed informal
        inquiry initiated by the SEC's Division of Enforcement in September 2003
        relating to the restatements in August 2003 of previously reported results
        by
        FirstEnergy and the Ohio Companies, and the Davis-Besse extended outage,
        have
        become the subject of a formal order of investigation. The SEC's formal order
        of
        investigation also encompasses issues raised during the SEC's examination
        of
        FirstEnergy and the Companies under PUHCA. Concurrent with this notification,
        FirstEnergy received a subpoena asking for background documents and documents
        related to the restatements and Davis-Besse issues. On December 30, 2004,
        FirstEnergy received a subpoena asking for documents relating to issues raised
        during the SEC's PUHCA examination. On August 24, 2005 additional
        information was requested regarding Davis-Besse related disclosures, which
        FirstEnergy has provided. FirstEnergy has cooperated fully with the informal
        inquiry and continues to do so with the formal investigation.
  73
  On
        August 22,
        2005, a class action complaint was filed against OE in Jefferson County,
        Ohio
        Common Pleas Court, seeking compensatory and punitive damages to be determined
        at trial based on claims of negligence and eight other tort counts alleging
        damages from W.H. Sammis Plant air emissions. The two named plaintiffs are
        also
        seeking injunctive relief to eliminate harmful emissions and repair property
        damage and the institution of a medical monitoring program for class members.
 
 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 decide 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 10(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. This
        EITF issue will
        not have a material impact on OE's financial results.
 
 *SFAS
        155 -
“Accounting for Certain Hybrid Financial Instruments-an amendment of FASB
        Statements No. 133 and 140”*
  In February 2006, the FASB issued SFAS 155 which amends SFAS 133 “Accounting for
        Derivative Instruments and Hedging Activities,” (SFAS 133) and SFAS 140
“Accounting for Transfers and Servicing of Financial Assets and Extinguishments
        of Liabilities.” This Statement permits fair value remeasurement for any hybrid
        financial instrument that contains an embedded derivative that otherwise
        would
        require bifurcation, clarifies which interest-only strips and principal-only
        strips are not subject to the requirements of SFAS 133, establishes a
        requirement to evaluate interests in securitized financial assets to identify
        interests that are freestanding derivatives or that are hybrid financial
        instruments that contain an embedded derivative requiring bifurcation, clarifies
        that concentrations of credit risk in the form of subordination are not embedded
        derivatives and amends SFAS 140 to eliminate the prohibition on a qualifying
        special-purpose entity from holding a derivative financial instrument that
        pertains to a beneficial interest other than another derivative instrument.
        This
        Statement is effective for all financial instruments acquired or issued
        beginning January 1, 2007. OE is currently evaluating the impact of this
        Statement on its financial statements.
  74
  **THE
                    CLEVELAND ELECTRIC ILLUMINATING
                    COMPANY****CONSOLIDATED
                    STATEMENTS OF INCOME AND COMPREHENSIVE
                    INCOME****(Unaudited)****Three
                    Months Ended****March
                    31,****2006**
                
                **2005****STATEMENTS
                    OF INCOME**
                
                ***(In
                    thousands)*****OPERATING
                    REVENUES**
                
                $
                407,810
                
                $
                433,173**OPERATING
                    EXPENSES AND TAXES:**Fuel
                
                
                13,563
                
                
                18,327Purchased
                    power
                
                
                135,990
                
                
                142,884Nuclear
                    operating costs
                
                
                -
                
                
                58,727Other
                    operating costs
                
                
                72,895
                
                
                63,573Provision
                    for
                    depreciation
                
                
                17,201
                
                
                31,115Amortization
                    of regulatory assets
                
                
                31,530
                
                
                54,026Deferral
                    of
                    new regulatory assets
                
                
                (22,746
                )
                
                (25,288
                )General
                    taxes
                
                
                35,070
                
                
                38,887Income
                    taxes
                
                
                36,125
                
                
                4,877Total
                    operating expenses and taxes
                
                
                319,628
                
                
                387,128**OPERATING
                    INCOME**
                
                
                88,182
                
                
                46,045**OTHER
                    INCOME (net of income taxes)**
                
                
                18,290
                
                
                4,304**NET
                    INTEREST CHARGES:**Interest
                    on
                    long-term debt
                
                
                27,185
                
                
                27,952Allowance
                    for
                    borrowed funds used during construction
                
                
                (673
                )
                
                411Other
                    interest
                    expense
                
                
                7,547
                
                
                6,514Net
                    interest
                    charges
                
                
                34,059
                
                
                34,877**NET
                    INCOME**
                
                
                72,413
                
                
                15,472**PREFERRED
                    STOCK DIVIDEND REQUIREMENTS**
                
                
                -
                
                
                2,918**EARNINGS
                    ON COMMON STOCK**
                
                $
                72,413
                
                $
                12,554**STATEMENTS
                    OF COMPREHENSIVE INCOME****NET
                    INCOME**
                
                $
                72,413
                
                $
                15,472**OTHER
                    COMPREHENSIVE INCOME (LOSS):**Unrealized
                    loss on available for sale securities
                
                
                -
                
                
                (1,221
                )Income
                    tax
                    benefit related to other comprehensive income
                
                
                -
                
                
                504Other
                    comprehensive loss, net of tax
                
                
                -
                
                
                (717
                )**TOTAL
                    COMPREHENSIVE INCOME**
                
                $
                72,413
                
                $
                14,755The
                    preceding
                    Notes to Consolidated Financial Statements as they relate to
                    The Cleveland
                    ElectricIlluminating
                    Company are an integral part of these statements.
   75
  **THE
                      CLEVELAND ELECTRIC ILLUMINATING
                      COMPANY****CONSOLIDATED
                      BALANCE SHEETS****(Unaudited)****March
                      31,**
                  
                  **December
                      31,****2006**
                  
                  **2005*****(In
                      thousands)*****ASSETS****UTILITY
                      PLANT:**In
                      service
                  
                  $
                  2,055,348
                  
                  $
                  2,030,935Less
                      -
                      Accumulated provision for depreciation
                  
                  
                  799,281
                  
                  
                  788,9671,256,067
                  
                  
                  1,241,968Construction
                      work in progress
                  
                  
                  59,756
                  
                  
                  51,1291,315,823
                  
                  
                  1,293,097**OTHER
                      PROPERTY AND INVESTMENTS:**Investment
                      in
                      lessor notes
                  
                  
                  519,618
                  
                  
                  564,166Long-term
                      notes receivable from associated companies
                  
                  
                  1,058,626
                  
                  
                  1,057,337Other
                  
                  
                  12,779
                  
                  
                  12,8401,591,023
                  
                  
                  1,634,343**CURRENT
                      ASSETS:**Cash
                      and cash
                      equivalents
                  
                  
                  217
                  
                  
                  207Receivables-Customers
                      (less accumulated provisions of $5,431,000 and $5,180,000,respectively,
                      for uncollectible accounts)
                  
                  
                  250,546
                  
                  
                  268,427Associated
                      companies
                  
                  
                  42,435
                  
                  
                  86,564Other
                  
                  
                  3,958
                  
                  
                  16,466Notes
                      receivable from associated companies
                  
                  
                  28,535
                  
                  
                  19,378Prepayments
                      and other
                  
                  
                  1,388
                  
                  
                  1,903327,079
                  
                  
                  392,945**DEFERRED
                      CHARGES AND OTHER ASSETS:**Goodwill
                  
                  
                  1,688,521
                  
                  
                  1,688,966Regulatory
                      assets
                  
                  
                  857,683
                  
                  
                  862,193Prepaid
                      pension costs
                  
                  
                  138,047
                  
                  
                  139,012Property
                      taxes
                  
                  
                  63,500
                  
                  
                  63,500Other
                  
                  
                  39,874
                  
                  
                  27,6142,787,625
                  
                  
                  2,781,285$
                  6,021,550
                  
                  $
                  6,101,670**CAPITALIZATION
                      AND LIABILITIES****CAPITALIZATION:**Common
                      stockholder's equity-Common
                      stock,
                      without par value, authorized 105,000,000 shares -79,590,689
                      shares outstanding
                  
                  $
                  1,355,897
                  
                  $
                  1,354,924Retained
                      earnings
                  
                  
                  596,563
                  
                  
                  587,150Total
                      common
                      stockholder's equity
                  
                  
                  1,952,460
                  
                  
                  1,942,074Long-term
                      debt
                      and other long-term obligations
                  
                  
                  1,887,074
                  
                  
                  1,939,3003,839,534
                  
                  
                  3,881,374**CURRENT
                      LIABILITIES:**Currently
                      payable long-term debt
                  
                  
                  118,370
                  
                  
                  75,718Short-term
                      borrowings-Associated
                      companies
                  
                  
                  209,647
                  
                  
                  212,256Other
                  
                  
                  94,000
                  
                  
                  140,000Accounts
                      payable-Associated
                      companies
                  
                  
                  64,853
                  
                  
                  74,993Other
                  
                  
                  5,380
                  
                  
                  4,664Accrued
                      taxes
                  
                  
                  137,178
                  
                  
                  121,487Accrued
                      interest
                  
                  
                  31,688
                  
                  
                  18,886Lease
                      market
                      valuation liability
                  
                  
                  60,200
                  
                  
                  60,200Other
                  
                  
                  30,750
                  
                  
                  61,308752,066
                  
                  
                  769,512**NONCURRENT
                      LIABILITIES:**Accumulated
                      deferred income taxes
                  
                  
                  555,320
                  
                  
                  554,828Accumulated
                      deferred investment tax credits
                  
                  
                  23,001
                  
                  
                  23,908Lease
                      market
                      valuation liability
                  
                  
                  593,000
                  
                  
                  608,000Asset
                      retirement obligation
                  
                  
                  8,117
                  
                  
                  8,024Retirement
                      benefits
                  
                  
                  83,641
                  
                  
                  83,414Deferred
                      revenues - electric service programs
                  
                  
                  67,205
                  
                  
                  71,261Other
                  
                  
                  99,666
                  
                  
                  101,3491,429,950
                  
                  
                  1,450,784**COMMITMENTS
                      AND CONTINGENCIES (Note 10)**$
                  6,021,550
                  
                  $
                  6,101,670The
                      preceding
                      Notes to Consolidated Financial Statements as they relate to
                      The Cleveland
                      Electric Illuminating Company are an integralpart
                      of these
                      balance sheets.
   76
   **THE
                        CLEVELAND ELECTRIC ILLUMINATING
                        COMPANY****CONSOLIDATED
                        STATEMENTS OF CASH FLOWS****(Unaudited)****Three
                        Months Ended****March
                        31,****2006**
                    
                    **2005*****(In
                        thousands)*****CASH
                        FLOWS FROM OPERATING ACTIVITIES:**Net
                        income
                    
                    
                    
                    
                    $
                    72,413
                    
                    $
                    15,472Adjustments
                        to
                        reconcile net income to net cash from operating
                        activities-Provision
                        for
                        depreciation
                    
                    
                    
                    
                    
                    17,201
                    
                    
                    31,115Amortization
                        of regulatory assets
                    
                    
                    
                    
                    
                    31,530
                    
                    
                    54,026Deferral
                        of
                        new regulatory assets
                    
                    
                    
                    
                    
                    (22,746
                    )
                    
                    (25,288
                    )Nuclear
                        fuel
                        and capital lease amortization
                    
                    
                    
                    
                    
                    60
                    
                    
                    4,610Deferred
                        rents
                        and lease market valuation liability
                    
                    
                    
                    
                    
                    (54,821
                    )
                    
                    (53,469
                    )Deferred
                        income taxes and investment tax credits, net
                    
                    
                    
                    
                    
                    (402
                    )
                    
                    (4,506
                    )Deferred
                        purchased power costs
                    
                    
                    
                    
                    
                    (7,780
                    )
                    
                    -Accrued
                        compensation and retirement benefits
                    
                    
                    
                    
                    
                    (172
                    )
                    
                    (3,203
                    )Decrease
                        (increase) in operating assets-Receivables
                    
                    
                    
                    
                    
                    74,518
                    
                    
                    84,890Materials
                        and
                        supplies
                    
                    
                    
                    
                    
                    -
                    
                    
                    (22,336
                    )Prepayments
                        and other current assets
                    
                    
                    
                    
                    
                    515
                    
                    
                    627Increase
                        (decrease) in operating liabilities-Accounts
                        payable
                    
                    
                    
                    
                    
                    (9,424
                    )
                    
                    39,238Accrued
                        taxes
                    
                    
                    
                    
                    
                    15,691
                    
                    
                    (21,198
                    )Accrued
                        interest
                    
                    
                    
                    
                    
                    12,802
                    
                    
                    12,031Electric
                        service prepayment programs
                    
                    
                    
                    
                    
                    (4,056
                    )
                    
                    (5,451
                    )Other
                    
                    
                    
                    
                    
                    81
                    
                    
                    (3,358
                    )Net
                        cash
                        provided from operating activities
                    
                    
                    
                    
                    
                    125,410
                    
                    
                    103,200**CASH
                        FLOWS FROM FINANCING ACTIVITIES:**Redemptions
                        and Repayments-Preferred
                        stock
                    
                    
                    
                    
                    
                    -
                    
                    
                    (97,900
                    )Long-term
                        debt
                    
                    
                    
                    
                    
                    (172
                    )
                    
                    (330
                    )Short-term
                        borrowings, net
                    
                    
                    
                    
                    
                    (57,760
                    )
                    
                    (29,683
                    )Dividend
                        Payments-Common
                        stock
                    
                    
                    
                    
                    
                    (63,000
                    )
                    
                    (55,000
                    )Preferred
                        stock
                    
                    
                    
                    
                    
                    -
                    
                    
                    (2,260
                    )Net
                        cash used
                        for financing activities
                    
                    
                    
                    
                    
                    (120,932
                    )
                    
                    (185,173
                    )**CASH
                        FLOWS FROM INVESTING ACTIVITIES:**Property
                        additions
                    
                    
                    
                    
                    
                    (34,410
                    )
                    
                    (33,683
                    )Loan
                        repayments from (loans to) associated companies, net
                    
                    
                    
                    
                    
                    (9,158
                    )
                    
                    90,788Investments
                        in
                        lessor notes
                    
                    
                    
                    
                    
                    44,548
                    
                    
                    32,470Proceeds
                        from
                        nuclear decommissioning trust fund sales
                    
                    
                    
                    
                    
                    -
                    
                    
                    132,805Investments
                        in
                        nuclear decommissioning trust funds
                    
                    
                    
                    
                    
                    -
                    
                    
                    (140,061
                    )Other
                    
                    
                    
                    
                    
                    (5,448
                    )
                    
                    (336
                    )Net
                        cash
                        provided from (used for) investing activities
                    
                    
                    
                    
                    
                    (4,468
                    )
                    
                    81,983Net
                        increase
                        in cash and cash equivalents
                    
                    
                    
                    
                    
                    10
                    
                    
                    10Cash
                        and cash
                        equivalents at beginning of period
                    
                    
                    
                    
                    
                    207
                    
                    
                    197Cash
                        and cash
                        equivalents at end of period
                    
                    
                    
                    
                    $
                    217
                    
                    $
                    207The
                        preceding
                        Notes to Consolidated Financial Statements as they relate
                        to The Cleveland
                        Electric Illuminating Companyare
                        an
                        integral part of these statements.
  77
 
 ***Report
        of Independent Registered Public Accounting Firm***
 
 
 
 
 
 
 
 
 
 To
        the Stockholder
        and Board of
 Directors
        of The
        Cleveland Electric Illuminating Company:
 
 We
        have reviewed the
        accompanying consolidated balance sheet of The Cleveland Electric Illuminating
        Company and its subsidiaries as of March 31, 2006 and the related consolidated
        statements of income, comprehensive income and cash flows for each of the
        three-month periods ended March 31, 2006 and 2005. These interim financial
        statements are the responsibility of the Company’s management.
 
 We
        conducted our
        review in accordance with the standards of the Public Company Accounting
        Oversight Board (United States). A review of interim financial information
        consists principally of applying analytical procedures and making inquiries
        of
        persons responsible for financial and accounting matters. It is substantially
        less in scope than an audit conducted in accordance with the standards of
        the
        Public Company Accounting Oversight Board, the objective of which is the
        expression of an opinion regarding the financial statements taken as a whole.
        Accordingly, we do not express such an opinion.
 
 Based
        on our review,
        we are not aware of any material modifications that should be made to the
        accompanying consolidated interim financial statements for them to be in
        conformity with accounting principles generally accepted in the United States
        of
        America.
 
 We
        previously
        audited, in accordance with the standards of the Public Company Accounting
        Oversight Board (United States), the consolidated balance sheet as of December
        31, 2005, and the related consolidated statements of income, capitalization,
        common stockholder’s equity, preferred stock, cash flows and taxes for the year
        then ended (not presented herein), and in our report (which contained references
        to the Company’s change in its method of accounting for asset retirement
        obligations as of January 1, 2003 and conditional asset retirement obligations
        as of December 31, 2005 as discussed in Note 2(G) and Note 11 to those
        consolidated financial statements and the Company’s change in its method of
        accounting for the consolidation of variable interest entities as of December
        31, 2003 as discussed in Note 6 to those consolidated financial statements)
        dated February 27, 2006, we expressed an unqualified opinion on those
        consolidated financial statements.
 
 In
        our opinion, the
        information set forth in the accompanying consolidated balance sheet as of
        December 31, 2005, is fairly stated in all material respects in relation to
        the consolidated balance sheet from which it has been derived.
 
 
 
 
 PricewaterhouseCoopers
        LLP
 Cleveland,
        Ohio
 May
        8,
        2006
 
  78
  **THE
        CLEVELAND ELECTRIC ILLUMINATING COMPANY**
 
 **MANAGEMENT’S
        DISCUSSION AND ANALYSIS OF**
 **RESULTS
        OF
        OPERATIONS AND FINANCIAL CONDITION**
 
 
 CEI is a wholly owned, electric utility subsidiary of FirstEnergy. CEI conducts
        business in portions of Ohio, providing regulated electric distribution
        services. CEI also provides generation services to those customers electing
        to
        retain CEI as their power supplier. CEI’s power supply requirements are
        primarily provided by FES - an affiliated
        company.
 
 **FirstEnergy
        Intra-System Generation Asset Transfers**
 
 On
        May 13,
        2005, Penn, and on May 18, 2005, the Ohio Companies, entered into certain
        agreements implementing a series of intra-system generation asset transfers
        that
        were completed in the fourth quarter of 2005. The asset transfers resulted
        in
        the respective undivided ownership interests of the Ohio Companies and Penn
        in
        FirstEnergy’s nuclear and non-nuclear generation assets being owned by NGC and
        FGCO, respectively.
 
 On
        October 24,
        2005, CEI completed the intra-system transfer of non-nuclear generation assets
        to FGCO. Prior to the transfer, FGCO, as lessee under a Master Facility Lease
        with the Ohio Companies and Penn, leased, operated and maintained the
        non-nuclear generation assets that it now owns. The asset transfers were
        consummated pursuant to FGCO's purchase option under the Master Facility
        Lease.
 
 On
        December 16,
        2005, CEI completed the intra-system transfer of their ownership interests
        in
        the nuclear generation assets to NGC through a sale at net book value. FENOC
        continues to operate and maintain the nuclear generation assets.
 
 These
        transactions
        were undertaken pursuant to the Ohio Companies’ and Penn’s restructuring plans
        that were approved by the PUCO and the PPUC, respectively, under applicable
        Ohio
        and Pennsylvania electric utility restructuring legislation. Consistent with
        the
        restructuring plans, generation assets that had been owned by the Ohio Companies
        and Penn were required to be separated from the regulated delivery business
        of
        those companies through transfer to a separate corporate entity. The
        transactions essentially completed the divestitures contemplated by the
        restructuring plans by transferring the ownership interests to NGC and FGCO
        without impacting the operation of the plants.
 
 The
        transfers will
        affect CEI’s near-term results with reductions in both revenues and expenses.
        Revenues are reduced due to the termination of certain arrangements with
        FES,
        under which CEI previously sold its nuclear-generated KWH to FES and leased
        its
        non-nuclear generation assets to FGCO, a subsidiary of FES. CEI’s expenses are
        lower due to the nuclear fuel and operating costs assumed by NGC as well
        as
        depreciation and property tax expenses assumed by FGCO and NGC related to
        the
        transferred generating assets.With respect to CEI's retained leashold interests
        in the Bruce Mansfield Plant, CEI has continued the fossil generation KWH
        sales
        arrangement with FES and continues to be obligated on the applicable portion
        of
        expenses related to those interests. In addition, CEI receives interest
        income on associated company notes receivable from the transfer of its
        generation net assets. FES will continue to provide CEI’s PLR requirements under
        revised purchased power arrangements for the three-year period beginning
        January 1, 2006 (see Regulatory Matters).
  79
  The
        effects on CEI’s
        results of operations in the first quarter of 2006 compared to the first
        quarter
        of 2005 from the generation asset transfers (also reflecting CEI's retained
        leasehold interests discussed above) are summarized in the following table:
 
 **Intra-System
                  Generation Asset Transfers -****First
                  Quarter 2006 vs First Quarter 2005 Income Statement
                  Effects*****Increase
                  (Decrease)***
              
              ***(In
                  millions)***Operating
                  Revenues:Non-nuclear
                  generating units rent
              
              $
              (15
              )
(a)Nuclear
                  generated KWH sales
              
              
              (53
              )
(b)Total - Operating Revenues Effect
              
              
              (68
              )Operating
                  Expenses and Taxes:Fuel
                  costs -
                  nuclear
              
              
              (6
              )
(c)Nuclear
                  operating costs
              
              
              (58
              )
(c)Provision
                  for
                  depreciation
              
              
              (19
              )
(d)General
                  taxes
              
              
              (4
              )
(e)Income
                  taxes
              
              
              8
              (i)Total-
                  Operating Expenses and Taxes Effect
              
              
              (79
              )Operating
                  Income Effect
              
              
              11Other
                  Income:Interest
                  income from notes receivable
              
              
              16
              (f)Nuclear decommissioning trust earnings
              
              
              (2
              )
(g)Income
                  taxes
              
              
              (6
              ) 
(i)Total-Other
                  Income Effect
              
              
              8Net
                  Interest
                  Charges:Allowance
                  for
                  funds used during construction
              
              
              1
              (h)Total-Net
                  Interest Charges Effect
              
              
              (1
              )Net
                  Income
                  Effect
              
              $
              20(a)
                  Elimination of non-nuclear generation assets lease to
                  FGCO.(b)
                  Reduction
                  of nuclear generated wholesale KWH sales to FES.(c)
                  Reduction
                  of nuclear fuel and operating costs.(d)
                  Reduction
                  of depreciation expense and asset retirement obligation accretion
                  related
                  to generation assets.(e)
                  Reduction
                  of property tax expense on generation assets.(f)
                  Interest
                  income on associated company notes receivable from the transfer
                  of
                  generation net assets.(g)
                  Reduction
                  of earnings on nuclear decommissioning trusts.(h)
                  Absence in
                  2006 of adjustment to 2005 allowance for borrowed funds used during
                  construction on generation assets transferred.(i)
                  Income tax
                  effect of the above adjustments.
 
 **Results
        of Operations**
 
 Earnings on common stock in the first quarter of 2006 increased to $72 million
        from $13 million in the first quarter of 2006. This increase resulted
        primarily from lower operating expenses and taxes and increased other income,
        partially offset by lower operating revenues. These changes were principally
        a
        result of the effects of the generation asset transfer shown in the table
        above.
 
 *Operating
        Revenues*
 
 Operating revenues decreased by $25 million or 5.9% in the first quarter
        of 2006
        from the same period in 2005. Excluding
        the
        generation asset transfer effects discussed above, operating revenues increased
        $43 million due to an $88 million increase in retail generation sales
        revenues and a $19 million reduction in customer shopping incentives, partially
        offset by a $44 million decrease in distribution revenues and an
        $18 million decrease in MSG wholesale sales.
 
 Retail generation revenues increased $88 million (residential -
        $38 million, commercial - $32 million and industrial -
        $18 million) due to increased KWH sales and higher unit prices. The higher
        unit prices reflected the rate stabilization charge that became effective
        in
        January 2006 under the RCP. The increase in generation KWH sales resulted
        from
        decreased customer shopping. Generation services provided by alternative
        suppliers as a percent of total sales deliveries in CEI's service area decreased
        in all customer classes by the following percentage points: residential -
        59.2%,
        commercial - 38.9% and industrial - 6.3%. The decreased shopping resulted
        from
        alternative energy suppliers terminating their supply arrangements with CEI's
        shopping customers in the fourth quarter of 2005.
  80
 
 Non-affiliated wholesale sales revenues decreased by $18 million due to the
        cessation of the MSG sales arrangements under CEI’s transition plan in December
        2005. CEI had been required to provide the MSG to non-affiliated alternative
        suppliers.
 
 Revenues from distribution throughput decreased $44 million in the first
        quarter
        of 2006 compared with the corresponding quarter in 2005. The decrease in
        all
        customer classes (residential - $5 million, commercial - $22 million and
        industrial - $17 million) primarily
        reflected
        lower unit prices and decreased KWH deliveries. The lower unit prices reflected
        the completion of the generation-related transition cost recovery under CEI’s
        transition plan in 2005, partially offset by the recovery of MISO costs
        beginning in 2006 (see Outlook -- Regulatory Matters). The lower
        KWH
        distribution deliveries to residential and commercial customers reflected
        the
        impact of milder weather conditions in the first quarter of 2006 compared
        to the
        same period of 2005.
 
 Under the Ohio transition plan, CEI had provided incentives to customers
        to
        encourage switching to alternative energy providers, reducing CEI's revenues.
        These revenue reductions, which were deferred for future recovery and did
        not
        affect current period earnings, ceased in 2006, resulting in a $19 million
        revenue increase as discussed above.
 
 Changes in electric generation sales and distribution deliveries in the first
        quarter of 2006 from the first quarter of 2005 are summarized in the following
        table:
 
 **Changes
                  in KWH Sales****Increase
                  (Decrease)**Electric
                  Generation:Retail
              
              
              46.5
              %Wholesale:Non-Associated
                  Companies
              
              
              (94.5
              )%Associated
                  Companies(1)
              
              
              (64.6
              )%**Total
                  Electric Generation Sales**
              
              
              (13.9
              )%Distribution
                  Deliveries:Residential
              
              
              (2.3
              )%Commercial
              
              
              (5.7
              )%Industrial
              
              
              (3.7
              )%**Total
                  Distribution Deliveries**
              
              
              (3.8
              )%
 
 (1)  Change
        reflects
        impact of generation asset transfers.
 
 *Operating
        Expenses and Taxes*
 
 Total operating expenses and taxes decreased by $68 million in the first
        quarter
        of 2006 from the same quarter of 2005 principally due to the asset transfer
        effects as shown in the table above. Excluding the asset transfer effects,
        the
        following table presents changes from the prior year by expense
        category:
 
 **Operating
                  Expenses and Taxes - Changes****Increase
                  (Decrease)**
              
              ***(In
                  millions)***Fuel
                  costs
              
              $
              1Purchased
                  power costs
              
              
              (7
              )Other
                  operating costs
              
              
              9Provision
                  for
                  depreciation
              
              
              5Amortization
                  of regulatory assets
              
              
              (22
              )Deferral
                  of
                  new regulatory assets
              
              
              3Income
                  taxes
              
              
              23**Total
                  operating expenses and taxes**
              
              $
              12
 
 Lower purchased power costs in the first quarter of 2006 compared to the
        first
        quarter of 2005 primarily reflected lower unit prices associated with the
        new
        power supply agreement with FES, RCP fuel deferral of $8 million and a
        purchased power lease credit amortization of $8 million. Under the RCP that
        was
        effective January 1, 2006, CEI can defer increased fuel costs (i.e., in
        excess of 2002 baseline amounts). The amortization is for the above-market
        lease
        liability related to an existing Beaver Valley Unit 2 purchased power
        arrangement with TE. The lease credit amortization had been previously included
        in CEI's nuclear operating costs and the related nuclear generation KWH
        purchased from TE had then been sold to FES. Subsequent to the generation
        asset
        transfer, CEI now retains this purchased power from TE to meet a portion
        of its
        PLR obligation and, consequently, the lease amortization is now included
        as part
        of CEI's purchased power costs. These decreases were partially offset by
        the
        impact of an increase in KWH purchased to meet the higher retail generation
        sales requirements. Higher other operating costs reflect increased transmission
        expenses, primarily related to MISO Day 2 operations that began on April 1,
        2005.
  81
  Excluding the effects of the generation asset transfers, the increase in
        depreciation in the first quarter of 2006 compared with the first quarter
        of
        2005 was attributable to a higher level of depreciable distribution property
        in
        2006. Lower
        amortization
        of regulatory assets reflected the completion of generation-related transition
        cost amortization under CEI’s transition plan, partially offset by the
        amortization of deferred MISO costs that are being recovered in 2006. The
        decreased deferral of new regulatory assets was primarily due to the termination
        of the shopping incentive deferrals ($19 million), partially offset by the
        RCP deferral of distribution costs and related interest ($15 million) and
        increased deferred MISO costs ($1 million).
 
 Increased
        income
        taxes in the first quarter of 2006 compared to the same period last year
        were
        primarily due to an increase in taxable income, partially offset by a reduction
        in the tax rates due to the continuing phase-out of the income-based Ohio
        franchise tax.
 
 *Other
        Income*
 
 The
        increase in
        other income of $14 million was primarily due to interest income on associated
        company notes receivable from the generation asset transfers discussed above.
        Excluding the effects of the asset transfer, other income increased
        $6 million due to the absence in 2006 of $5 million in expenses related to
        the sales of customer receivables and a $2 million NRC fine related to the
        Davis-Besse Plant in the first quarter of 2005. The customer receivables
        sales
        expenses ceased in 2005 as result of the renewal of the CFC financing
        arrangement.
 
 *Net
        Interest
        Charges*
 
 Net interest charges continued to trend lower, decreasing by $1 million in
        the
        first quarter of 2006 from the same quarter last year.
 
 *Preferred
        Stock
        Dividend Requirements*
 
 Preferred stock dividend requirements decreased by $3 million in the first
        quarter of 2006, compared to the same period last year as a result of the
        optional redemption of CEI's remaining outstanding preferred stock in
        2005.
 
 **Capital
        Resources and Liquidity**
 
 During
        2006, CEI
        expects to meet its contractual obligations with cash from operations and
        short-term credit arrangements. Thereafter, CEI expects to use a combination
        of
        cash from operations and funds from the capital markets.
 
 *Changes
        in Cash
        Position*
 
 As
        of March 31,
        2006, CEI had $217,000 of cash and cash equivalents, compared with $207,000
        as
        of December 31, 2005. The major sources of changes in these balances are
        summarized below.
 
 *Cash
        Flows from
        Operating Activities*
 
 Cash provided from operating activities during the first quarter of 2006,
        compared with the first quarter of 2005, were as follows:
 
 **Three
                  Months Ended**
                **March
                  31,****Operating
                  Cash Flows**
              
              **2006**
              
              **2005*****(in
                  millions)***Cash
                  earnings(1)
              
              $
              31
              
              $
              13Working
                  capital and other
              
              
              94
              
              
              90Net
                  cash
                  provided from operating activities
              
              $
              125
              
              $
              103
 (1)
                Cash
                    earnings
                    is a non-GAAP measure (see reconciliation
                    below).
   82
 
 Cash earnings (in the table above) are not a measure of performance
        calculated in accordance with GAAP. CEI believes that cash earnings are 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****March
                  31,****Reconciliation
                  of Cash Earnings**
              
              **2006**
              
              **2005*****(In
                  millions)***Net
                  Income
                  (GAAP)
              
              $
              72
              
              $
              15Non-Cash
                  Charges (Credits):Provision
                  for
                  depreciation
              
              
              17
              
              
              31Amortization
                  of regulatory assets
              
              
              32
              
              
              54Deferral
                  of
                  new regulatory assets
              
              
              (22
              )
              
              (25
              )Nuclear
                  fuel
                  and capital lease amortization
              
              
              -
              
              
              4Amortization
                  of electric service obligation
              
              
              (4
              )
              
              (5
              )Deferred
                  rents
                  and lease market valuation liability
              
              
              (55
              )
              
              (53
              )Deferred
                  income taxes and investment tax credits, net
              
              
              (1
              )
              
              (4
              )Deferred
                  purchased power costs
              
              
              (8
              )
              
              -Accrued
                  compensation and retirement benefits
              
              
              -
              
              
              (4
              )Cash
                  earnings
                  (Non-GAAP)
              
              $
              31
              
              $
              13
 
 Net cash provided from operating activities increased by $22 million in the
        first quarter of 2006 from the first quarter of 2005 as a result of an $18
        million increase in cash earnings described above under "Results of Operations"
        and a $4 million increase from working capital and other cash flows.
 
 *Cash
        Flows from
        Financing Activities*
 
 Net cash used for financing activities decreased $64 million in the first
        quarter of 2006 from the first quarter of 2005. The decrease in funds used
        for
        financing activities primarily resulted from a $70 million reduction in net
        preferred stock and debt redemptions, partially offset by an $8 million increase
        in common stock dividend payments to FirstEnergy.
 
 CEI had $29 million of cash and temporary investments (which included short-term
        notes receivable from associated companies) and approximately $304 million
        of
        short-term indebtedness as of March 31, 2006. CEI has obtained
        authorization from the PUCO to incur short-term debt of up to $500 million
        (including through the available bank facility and the utility money pool
        described below). As of March 31, 2006, CEI had the capability to issue
        $129 million of additional FMB on the basis of property additions and
        retired bonds under the terms of its mortgage indenture. The issuance of
        FMB by
        CEI is subject to a provision of its senior note indenture generally limiting
        the incurrence of additional secured debt, subject to certain exceptions
        that
        would permit, among other things, the issuance of secured debt (including
        FMB)
        (i) supporting pollution control notes or similar obligations, or (ii) as
        an
        extension, renewal or replacement of previously outstanding secured debt.
        In
        addition, CEI is permitted under the indenture to incur additional secured
        debt
        not otherwise permitted by a specified exception of up to $576 million as
        of
        March 31, 2006. CEI has no restrictions on the issuance of preferred
        stock.
 
 CFC is a wholly owned subsidiary of CEI whose borrowings are secured by customer
        accounts receivable purchased from CEI and TE. CFC can borrow up to $200
        million
        under a receivables financing arrangement. As a separate legal entity with
        separate creditors, CFC would have to satisfy its obligations to creditors
        before any of its remaining assets could be made available to CEI. As of
        March
        31, 2006, the facility was drawn for $94 million.
 
 CEI has the ability to borrow from its regulated affiliates and FirstEnergy
        to
        meet its short-term working capital requirements. FESC administers this money
        pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries.
        Companies receiving a loan under the money pool agreements must repay the
        principal amount, together with accrued interest, within 364 days of borrowing
        the funds. The rate of interest is the same for each company receiving a
        loan
        from the pool and is based on the average cost of funds available through
        the
        pool. The average interest rate for borrowings in the first quarter of 2006
        was
        4.58%.
 
 CEI,
        FirstEnergy,
        OE, Penn, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as Borrowers, have
        entered into a syndicated $2 billion five-year revolving credit facility
        through a syndicate of banks that expires in June 2010. Borrowings under
        the
        facility are available to each Borrower separately and mature on the earlier
        of
        364 days from the date of borrowing and the commitment expiration date, as
        the same may be extended. CEI’s borrowing limit under the facility is
        $250 million subject to applicable regulatory approvals.
  83
 
 Under
        the revolving
        credit facility, borrowers may request the issuance of letters of credit
        expiring up to one year from the date of issuance. The stated amount of
        outstanding LOC will count against total commitments available under the
        facility and against the applicable borrower’s borrowing sub-limit.
 
 The
        revolving credit
        facility contains financial covenants requiring each borrower to maintain
        a
        consolidated debt to total capitalization ratio of no more than 65%. As of
        March 31, 2006, CEI's debt to total capitalization as defined under the
        revolving credit facility was 52%.
 
 The
        facility does
        not contain any provisions that either restrict CEI's ability to borrow or
        accelerate repayment of outstanding advances as a result of any change in
        its
        credit ratings. Pricing is defined in “pricing grids”, whereby the cost of funds
        borrowed under the facility is related to CEI's credit ratings.
 
 CEI’s access to the capital markets and the costs of financing are dependent
        on
        the ratings of its securities and the securities of FirstEnergy. The ratings
        outlook from S&P on all such securities is stable. The ratings outlook from
        Moody's and Fitch on all securities is positive.
 
 In
        April and May of
        2006, pollution control notes that were formerly obligations of CEI were
        refinanced and became obligations of FGCO and NGC. The
        proceeds from
        the refinancings were used to repay a portion of their associated company
        notes
        payable to CEI. CEI redeemed $117.8 million of pollution control notes
        having variable interest rates.
 
 *Cash
        Flows from
        Investing Activities*
 
 Net cash used for investing activities was $4 million in the first quarter
        of
        2006 compared to net cash provided from investing activities of $82 million
        in
        the first quarter of 2005. The change was primarily due to increased loans
        to
        associated companies, partially offset by a reduction in investments in lessor
        notes.
 
 CEI’s capital spending for the last three quarters of 2006 is expected to be
        about $85 million. These cash requirements are expected to be satisfied
        from internal cash and short-term credit arrangements. CEI’s
        capital
        spending for the period 2006-2010 is expected to be about $615 million of
        which
        approximately $122 million applies to 2006.
 
 **Off-Balance
        Sheet Arrangements**
  Obligations not included on CEI’s Consolidated Balance Sheet primarily consist
        of sale and leaseback arrangements involving the Bruce Mansfield Plant. As
        of
        March 31, 2006, the present value of these operating lease commitments, net
        of trust investments, total $96 million.
 
 **Outlook**
 
 The
        electric
        industry continues to transition to a more competitive environment and all
        of
        CEI’s customers can select alternative energy suppliers. CEI continues to
        deliver power to residential homes and businesses through its existing
        distribution system, which remains regulated. Customer rates have been
        restructured into separate components to support customer choice. CEI has
        a
        continuing responsibility to provide power to those customers not choosing
        to
        receive power from an alternative energy supplier subject to certain
        limits.
 
 *Regulatory
        Matters*
 
 Regulatory
        assets
        are costs which have been authorized by the PUCO and the FERC for recovery
        from
        customers in future periods or for which authorization is probable. Without
        the
        probability of such authorization, costs currently recorded as regulatory
        assets
        would have been charged to income as incurred. All regulatory assets are
        expected to be recovered under the provisions of CEI’s transition plan. CEI’s
        regulatory assets as of March 31, 2006 and December 31, 2005, were
        $858 million and $862 million, respectively.
 
 On October 21, 2003 the Ohio Companies filed the RSP case with the PUCO.
        On
        August 5, 2004, the Ohio Companies accepted the RSP as modified and
        approved by the PUCO in an August 4, 2004 Entry on Rehearing, subject to
        a CBP.
        The RSP was intended to establish generation service rates beginning
        January 1, 2006, in response to 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 arguments on the
        appeals. On May 3, 2006, the Supreme Court of Ohio issued an opinion affirming
        that order with respect to the approval of the rate stabilization charge,
        approval of the shopping credits, the grant of interest on shopping credit
        incentive deferral amounts, and approval of FirstEnergy’s financial separation
        plan. It remanded the approval of the RSP pricing back to the PUCO for further
        consideration of the issue as to whether the RSP, as adopted by the PUCO,
        provided for sufficient customer participation in the competitive
        marketplace.
  84
  Under provisions of the RSP, the PUCO had required the Ohio Companies to
        undertake a CBP to secure generation and allow for customer pricing
        participation in the competitive marketplace. Any acceptance of
        future competitive bid results would terminate the RSP pricing, with
        no accounting impacts to the RSP, and not until 12 months after the PUCO
        authorizes such termination. On December 9, 2004, the PUCO rejected the
        auction price results from the CBP for the generation supply period beginning
        January 1, 2006 and issued an entry stating that the pricing under the approved
        revised RSP would take effect on January 1, 2006. On February 23, 2006
        the CBP auction manager, National Economic Research Associates, notified
        the
        PUCO that a subsequent CBP to potentially provide firm generation service
        for
        the Ohio Companies' 2007 and 2008 actual load requirements could not proceed
        due
        to lack of interest, as there were no bidder applications submitted.
        Additionally, on March 20, 2006, the PUCO denied applications for rehearing
        filed by various parties regarding the PUCO's rules for the CBP. The above
        May 3, 2006 Supreme Court of Ohio opinion may require the PUCO to
        reconsider this customer pricing process.
 
 On
        January 4, 2006,
        the PUCO approved, with modifications, CEI’s RCP to supplement the RSP to
        provide customers with more certain rate levels than otherwise available
        under
        the RSP during the plan period. Major provisions of the RCP
        include:
  ·
                Maintaining
                    the existing level of base distribution rates through April 30, 2009
                    for CEI;·
                Deferring
                    and
                    capitalizing for future recovery (over a 25-year period) with
                    carrying
                    charges certain distribution costs to be incurred by all of the
                    Ohio
                    Companies during the period January 1, 2006 through December 31,
                    2008, not to exceed $150 million in each of the three
                    years;·
                Adjusting
                    the
                    RTC and extended RTC recovery periods and rate levels so that
                    full
                    recovery of authorized costs will occur as of December 31, 2010 for
                    CEI;·
                Reducing
                    the
                    deferred shopping incentive balances as of January 1, 2006 by up to
                    $85 million for CEI by accelerating the application of its
                    accumulated cost of removal regulatory liability; and·
                Deferring
                    and
                    capitalizing (for recovery over a 25-year period) increased fuel
                    costs
                    above the amount collected through the Ohio Companies’ fuel recovery
                    mechanism (in lieu of implementation of the GCAF
                    rider).
  The
        following table
        provides CEI’s estimated amortization of regulatory transition costs and
        deferred shopping incentives (including associated carrying charges) under
        the
        RCP for the period 2006 through 2010:
 
 **Amortization****Period**
              
              **Amortization*****(In
                  millions)***2006
              
              $
              972007
              
              
              1132008
              
              
              1302009
              
              
              2112010
              
              
              263**Total
                  Amortization**
              
              **$**
              **814**
 
 The
        PUCO’s January
        4, 2006 approval of the RCP also included approval of the Ohio
        Companies’ supplemental
        stipulation which was filed with the PUCO on November 4, 2005 and which was
        an
        additional component of the RCP filed on September 9, 2005. On
        January 10, 2006, the Ohio Companies filed a Motion for Clarification of
        the PUCO order approving the RCP. The Ohio Companies sought clarity on issues
        related to distribution deferrals, including requirements of the review process,
        timing for recognizing certain deferrals and definitions of the types of
        qualified expenditures. The Ohio Companies also sought confirmation that
        the
        list of deferrable distribution expenditures originally included in the revised
        stipulation fall within the PUCO order definition of qualified expenditures.
        On
        January 25, 2006, the PUCO issued an Entry on Rehearing granting in part,
        and denying in part, the Ohio Companies’ previous requests and clarifying issues
        referred to above. The PUCO granted the Ohio Companies’ requests to:
  ·
                Recognize
                    fuel
                    and distribution deferrals commencing January 1,
                    2006;·
                Recognize
                    distribution deferrals on a monthly basis prior to review by
                    the PUCO
                    Staff;
  85
  ·
                Clarify
                    that
                    the types of distribution expenditures included in the Supplemental
                    Stipulation may be deferred; and·
                Clarify
                    that
                    distribution expenditures do not have to be “accelerated” in order to be
                    deferred.
  The
        PUCO approved the Ohio Companies’ methodology for determining distribution
        deferral amounts, but denied the Motion in that the PUCO Staff must verify
        the
        level of distribution expenditures contained in current rates, as opposed
        to
        simply accepting the amounts contained in the Ohio Companies’ Motion. On
        February 3, 2006, several other parties filed applications for rehearing
        on the
        PUCO's January 4, 2006 Order. The Ohio Companies responded to the
        applications for rehearing on February 13, 2006. In an Entry on Rehearing
        issued by the PUCO on March 1, 2006, all motions for rehearing were denied.
        Certain of these parties have subsequently filed their notices of appeal
        with
        the Supreme Court of Ohio alleging various errors made by the PUCO in its
        order
        approving the RCP.
 
 On
        December 30,
        2004, CEI filed with the PUCO two applications related to the recovery of
        transmission and ancillary service related costs. The first application sought
        recovery of these costs beginning January 1, 2006. CEI requested that these
        costs be recovered through a rider that would be effective on January 1,
        2006 and adjusted each July 1 thereafter. The parties reached a settlement
        agreement that was approved by the PUCO on August 31, 2005. The incremental
        transmission and ancillary service revenues expected to be recovered from
        January through June 30, 2006 are approximately $24 million. This
        amount includes the recovery of the 2005 deferred MISO expenses as described
        below. On May 1, 2006, CEI filed a modification to the rider to 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. On August 31, 2005, the OCC
        appealed the PUCO's decision. All briefs have been filed. On March 20, 2006,
        the
        Ohio Supreme Court, on its own motion, consolidated the OCC's appeal of CEI's
        case with a similar case involving Dayton Power & Light Company. Oral
        argument is currently scheduled for May 10, 2006.
 
 On
        January 20,
        2006 the OCC sought rehearing of the PUCO approval of the recovery of deferred
        costs through the rider during the period January 1, 2006 through June 30,
        2006. The PUCO denied the OCC's application on February 6, 2006. On March
        23, 2006, the OCC appealed the PUCO's order to the Ohio Supreme Court. The
        OCC's
        brief is expected to be filed during the second quarter of 2006. The briefs
        of the PUCO and CEI will be due within thirty days of the OCC's filing. On
        March
        27, 2006, the OCC filed a motion to consolidate this appeal with the deferral
        appeals discussed above and to postpone oral arguments in the deferral appeal
        until after all briefs are filed in this most recent appeal of the rider
        recovery mechanism. On
        April 18, 2006,
        the Court denied both parts of the motion but on its own motion consolidated
        the
        OCC's appeal of CEI's case with a similar case of Dayton Power & Light
        Company and stayed briefing on these appeals.
 
 On
        November 1, 2005,
        FES filed two power sales agreements for approval with the FERC. One power
        sales
        agreement provided for FES to provide the PLR requirements of the Ohio Companies
        at a price equal to the retail generation rates approved by the PUCO for
        a
        period of three years beginning January 1, 2006. The Ohio Companies will be
        relieved of their obligation to obtain PLR power requirements from FES if
        the
        Ohio competitive bid process results in a lower price for retail customers.
        A
        similar power sales agreement between FES and Penn permits Penn to obtain
        its
        PLR power requirements from FES at a fixed price equal to the retail generation
        price during 2006. The PPUC approved Penn's plan with modifications on April
        20,
        2006 to use an RFP process to obtain its power supply requirements after
        2006.
 
 On
        December 29,
        2005, the FERC issued an order setting the two power sales agreements for
        hearing. The order criticized the Ohio competitive bid process, and required
        FES
        to submit additional evidence in support of the reasonableness of the prices
        charged in the power sales agreements. A pre-hearing conference was held
        on
        January 18, 2006 to determine the hearing schedule in this case. FES
        expects an initial decision to be issued in this case in late January 2007,
        as a
        result of the April 20, 2006 extension of the procedural schedule. The outcome
        of this proceeding cannot be predicted. FES has sought rehearing of the
        December 29, 2005 order and the FERC granted rehearing for future
        consideration on March 1, 2006.
 
 See
        Note 11 to
        the consolidated financial statements for further details and a complete
        discussion of regulatory matters in Ohio.
  86
 
 *Environmental
        Matters*
 
 CEI
        accrues
        environmental liabilities when it is probable that it has an obligation for
        such
        costs and can reasonably estimate the amount of such costs. Unasserted claims
        are reflected in CEI’s determination of environmental liabilities and are
        accrued in the period that they are both probable and reasonably
        estimable.
 
 *Regulation
        of
        Hazardous Waste*
 
 CEI has been named a PRP at waste disposal sites, which may require cleanup
        under the Comprehensive Environmental Response, Compensation and Liability
        Act
        of 1980. Allegations of disposal of hazardous substances at historical sites
        and
        the liability involved are often unsubstantiated and subject to dispute;
        however, federal law provides that all PRPs for a particular site are liable
        on
        a joint and several basis. Therefore, environmental liabilities that are
        considered probable have been recognized on the Consolidated Balance Sheet
        as of
        March 31, 2006, based on estimates of the total costs of cleanup, CEI’s
        proportionate responsibility for such costs and the financial ability of
        other
        unaffiliated entities to pay. Included in Other Noncurrent Liabilities are
        accrued liabilities aggregating approximately $1.7 million as of
        March 31, 2006.
 
 See Note 10(B) to the consolidated financial statements for further details
        and a complete discussion of environmental matters.
 
 *Other
        Legal
        Proceedings*
 
 *Power
        Outages
        and Related Litigation-*
 
 On
        August 14,
        2003, various states and parts of southern Canada experienced widespread
        power
        outages. The outages affected approximately 1.4 million customers in
        FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s
        final report in April 2004 on the outages concluded, among other things,
        that
        the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically,
        the
        final report concluded, among other things, that the initiation of the
        August 14, 2003 power outages resulted from an alleged failure of both
        FirstEnergy and ECAR to assess and understand perceived inadequacies within
        the
        FirstEnergy system; inadequate situational awareness of the developing
        conditions; and a perceived failure to adequately manage tree growth in certain
        transmission rights of way. The Task Force also concluded that there was
        a
        failure of the interconnected grid's reliability organizations (MISO and
        PJM) to
        provide effective real-time diagnostic support. The final report is publicly
        available through the Department of Energy’s 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
        March 31, 2006 for any expenditure 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 Company, Inc. as well) for claims paid to insureds
        for
        damages allegedly arising as a result of the loss of power on August 14,
        2003. The listed insureds in these cases, in many instances, are not customers
        of any FirstEnergy company. The fourth case involves the claim of a non-customer
        seeking reimbursement for losses incurred when its store was burglarized
        on
        August 14, 2003. On
        March 7,
        2006, the PUCO issued a ruling applicable to all pending cases. Among its
        various rulings, the PUCO consolidated all of the pending outage cases for
        hearing; limited the litigation to service-related claims by customers of
        the
        Ohio operating companies; dismissed FirstEnergy Corp. as a defendant; ruled
        that
        the U.S.-Canada Power System Outage Task Force Report was not admissible
        into
        evidence; and gave the plaintiffs additional time to amend their complaints
        to
        otherwise comply with the PUCO’s underlying order. The plaintiffs in
        one case have since filed an amended complaint. The named FirstEnergy companies
        have answered and also have filed a motion to dismiss the action, which is
        pending. Also, most complainants, along with the FirstEnergy companies, filed
        applications for rehearing with the PUCO over various rulings contained in
        the
        March 7, 2006 order. On April 26, 2006, the PUCO granted rehearing to allow
        the insurance company claimants, as insurers, to prosecute their claims in
        their
        name so long as they also identify the underlying insured entities and the
        Ohio
        utilities which provide their service. The PUCO denied all other motions
        for
        rehearing. No estimate of potential liability is available for any of these
        cases. 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.
        Following the PUCO's March 7, 2006 order, that action was voluntarily
        dismissed by the claimants.
   87
  FirstEnergy
        is
        vigorously defending these actions, but cannot predict the outcome of any
        of
        these proceedings or whether any further regulatory proceedings or legal
        actions
        may be initiated against the Companies. Although unable to predict the impact
        of
        these proceedings, if FirstEnergy or its subsidiaries were ultimately determined
        to have legal liability in connection with these proceedings, it could have
        a
        material adverse effect on FirstEnergy’s or its subsidiaries’ financial
        condition, results of operations and cash flows.
 
 *Other
        Legal
        Matters-*
 
 There
        are various
        lawsuits, claims (including claims for asbestos exposure) and proceedings
        related to CEI’s normal business operations pending against CEI and its
        subsidiaries. The other potentially material items not otherwise discussed
        above
        are described below.
 
 On
        October 20,
        2004, FirstEnergy was notified by the SEC that the previously disclosed informal
        inquiry initiated by the SEC's Division of Enforcement in September 2003
        relating to the restatements in August 2003 of previously reported results
        by
        FirstEnergy and the Ohio Companies, and the Davis-Besse extended outage,
        have
        become the subject of a formal order of investigation. The SEC's formal order
        of
        investigation also encompasses issues raised during the SEC's examination
        of
        FirstEnergy and the Companies under PUHCA. Concurrent with this notification,
        FirstEnergy received a subpoena asking for background documents and documents
        related to the restatements and Davis-Besse issues. On December 30, 2004,
        FirstEnergy received a subpoena asking for documents relating to issues raised
        during the SEC's PUHCA examination. On August 24, 2005 additional
        information was requested regarding Davis-Besse related disclosures, which
        FirstEnergy has provided. FirstEnergy has cooperated fully with the informal
        inquiry and will continue to do so with the formal investigation.
 
 The
        City of Huron
        filed a complaint against OE with the PUCO challenging the ability of electric
        distribution utilities to collect transition charges from a customer of a
        newly
        formed municipal electric utility. The complaint was filed on May 28, 2003,
        and OE timely filed its response on June 30, 2003. In a related filing, the
        Ohio Companies filed for approval with the PUCO 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 decide 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 10 (C)
        to the consolidated financial statements for further details and a complete
        discussion of other legal proceedings.
  88
 
 **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. This EITF issue will not have a material impact on CEI's
        financial results.
 
 *SFAS
        155 -
“Accounting for Certain Hybrid Financial Instruments-an amendment of FASB
        Statements No. 133 and 140”*
 
 In
        February 2006, the FASB issued SFAS 155 which amends SFAS 133 “Accounting for
        Derivative Instruments and Hedging Activities,” (SFAS 133) and SFAS 140
“Accounting for Transfers and Servicing of Financial Assets and Extinguishments
        of Liabilities.” This Statement permits fair value remeasurement for any hybrid
        financial instrument that contains an embedded derivative that otherwise
        would
        require bifurcation, clarifies which interest-only strips and principal-only
        strips are not subject to the requirements of SFAS 133, establishes a
        requirement to evaluate interests in securitized financial assets to identify
        interests that are freestanding derivatives or that are hybrid financial
        instruments that contain an embedded derivative requiring bifurcation, clarifies
        that concentrations of credit risk in the form of subordination are not embedded
        derivatives and amends SFAS 140 to eliminate the prohibition on a qualifying
        special-purpose entity from holding a derivative financial instrument that
        pertains to a beneficial interest other than another derivative instrument.
        This
        Statement is effective for all financial instruments acquired or issued
        beginning January 1, 2007. CEI is currently evaluating the impact of this
        Statement on its financial statements.
 
 
 
  89
  **THE
                    TOLEDO EDISON COMPANY****CONSOLIDATED
                    STATEMENTS OF INCOME AND COMPREHENSIVE
                    INCOME****(Unaudited)****Three
                    Months Ended****March
                    31,****2006**
                
                **2005****STATEMENTS
                    OF INCOME**
                
                ***(In
                    thousands)*****OPERATING
                    REVENUES**
                
                $
                217,977
                
                $
                241,755**OPERATING
                    EXPENSES AND TAXES:**Fuel
                
                
                9,762
                
                
                12,569Purchased
                    power
                
                
                72,418
                
                
                80,156Nuclear
                    operating costs
                
                
                17,332
                
                
                59,163Other
                    operating costs
                
                
                40,425
                
                
                34,348Provision
                    for
                    depreciation
                
                
                8,097
                
                
                14,680Amortization
                    of regulatory assets
                
                
                24,456
                
                
                34,865Deferral
                    of
                    new regulatory assets
                
                
                (10,654
                )
                
                (9,424
                )General
                    taxes
                
                
                12,931
                
                
                14,181Income
                    taxes
                    (benefit)
                
                
                14,418
                
                
                (3,968
                )Total
                    operating expenses and taxes
                
                
                189,185
                
                
                236,570**OPERATING
                    INCOME**
                
                
                28,792
                
                
                5,185**OTHER
                    INCOME (net of income taxes)**
                
                
                4,310
                
                
                2,659**NET
                    INTEREST CHARGES:**Interest
                    on
                    long-term debt
                
                
                2,790
                
                
                4,220Allowance
                    for
                    borrowed funds used during construction
                
                
                (214
                )
                
                443Other
                    interest
                    expense
                
                
                1,520
                
                
                2,816Net
                    interest
                    charges
                
                
                4,096
                
                
                7,479**NET
                    INCOME**
                
                
                29,006
                
                
                365**PREFERRED
                    STOCK DIVIDEND REQUIREMENTS**
                
                
                1,275
                
                
                2,211**EARNINGS
                    (LOSS) APPLICABLE TO COMMON STOCK**
                
                $
                27,731
                
                $
                (1,846
                )**STATEMENTS
                    OF COMPREHENSIVE INCOME****NET
                    INCOME**
                
                $
                29,006
                
                $
                365**OTHER
                    COMPREHENSIVE INCOME (LOSS):**Unrealized
                    loss on available for sale securities
                
                
                (1,138
                )
                
                (1,683
                )Income
                    tax
                    benefit related to other comprehensive income
                
                
                411
                
                
                695Other
                    comprehensive loss, net of tax
                
                
                (727
                )
                
                (988
                )**TOTAL
                    COMPREHENSIVE INCOME (LOSS)**
                
                $
                28,279
                
                $
                (623
                )The
                    preceding
                    Notes to Consolidated Financial Statements as they relate to
                    The Toledo
                    Edison Company are an
                    integral
                    part of these statements.
    90
  **THE
                      TOLEDO EDISON COMPANY****CONSOLIDATED
                      BALANCE SHEETS****(Unaudited)****March
                      31,**
                  
                  **December
                      31,****2006**
                  
                  **2005*****(In
                      thousands)*****ASSETS****UTILITY
                      PLANT:**In
                      service
                  
                  $
                  834,124
                  
                  $
                  824,677Less
                      -
                      Accumulated provision for depreciation
                  
                  
                  377,586
                  
                  
                  372,845456,538
                  
                  
                  451,832Construction
                      work in progress
                  
                  
                  36,277
                  
                  
                  33,920492,815
                  
                  
                  485,752**OTHER
                      PROPERTY AND INVESTMENTS:**Investment
                      in
                      lessor notes
                  
                  
                  169,463
                  
                  
                  178,798Nuclear
                      plant
                      decommissioning trusts
                  
                  
                  58,458
                  
                  
                  59,209Long-term
                      notes receivable from associated companies
                  
                  
                  436,446
                  
                  
                  436,178Other
                  
                  
                  1,770
                  
                  
                  1,781666,137
                  
                  
                  675,966**CURRENT
                      ASSETS:**Cash
                      and cash
                      equivalents
                  
                  
                  15
                  
                  
                  15Receivables-Customers
                  
                  
                  751
                  
                  
                  2,209Associated
                      companies
                  
                  
                  28,275
                  
                  
                  16,311Other
                  
                  
                  4,697
                  
                  
                  6,410Notes
                      receivable from associated companies
                  
                  
                  59,681
                  
                  
                  48,349Prepayments
                      and other
                  
                  
                  693
                  
                  
                  1,05994,112
                  
                  
                  74,353**DEFERRED
                      CHARGES AND OTHER ASSETS:**Goodwill
                  
                  
                  500,576
                  
                  
                  501,022Regulatory
                      assets
                  
                  
                  275,671
                  
                  
                  287,095Prepaid
                      pension costs
                  
                  
                  35,345
                  
                  
                  35,566Property
                      taxes
                  
                  
                  18,047
                  
                  
                  18,047Other
                  
                  
                  40,988
                  
                  
                  24,164870,627
                  
                  
                  865,894$
                  2,123,691
                  
                  $
                  2,101,965**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
                  
                  
                  473,894
                  
                  
                  473,638Accumulated
                      other comprehensive income
                  
                  
                  3,963
                  
                  
                  4,690Retained
                      earnings
                  
                  
                  192,159
                  
                  
                  189,428Total
                      common
                      stockholder's equity
                  
                  
                  865,686
                  
                  
                  863,426Preferred
                      stock
                  
                  
                  66,000
                  
                  
                  96,000Long-term
                      debt
                  
                  
                  237,722
                  
                  
                  237,7531,169,408
                  
                  
                  1,197,179**CURRENT
                      LIABILITIES:**Currently
                      payable long-term debt
                  
                  
                  53,650
                  
                  
                  53,650Accounts
                      payable-Associated
                      companies
                  
                  
                  30,004
                  
                  
                  46,386Other
                  
                  
                  3,085
                  
                  
                  2,672Notes
                      payable
                      to associated companies
                  
                  
                  120,228
                  
                  
                  64,689Accrued
                      taxes
                  
                  
                  69,745
                  
                  
                  49,344Lease
                      market
                      valuation liability
                  
                  
                  24,600
                  
                  
                  24,600Other
                  
                  
                  43,281
                  
                  
                  40,049344,593
                  
                  
                  281,390**NONCURRENT
                      LIABILITIES:**Accumulated
                      deferred income taxes
                  
                  
                  213,298
                  
                  
                  221,149Accumulated
                      deferred investment tax credits
                  
                  
                  11,622
                  
                  
                  11,824Lease
                      market
                      valuation liability
                  
                  
                  237,250
                  
                  
                  243,400Retirement
                      benefits
                  
                  
                  41,242
                  
                  
                  40,353Asset
                      retirement obligation
                  
                  
                  25,252
                  
                  
                  24,836Deferred
                      revenues - electric service programs
                  
                  
                  30,374
                  
                  
                  32,606Other
                  
                  
                  50,652
                  
                  
                  49,228609,690
                  
                  
                  623,396**COMMITMENTS
                      AND CONTINGENCIES (Note 10)**$
                  2,123,691
                  
                  $
                  2,101,965The
                      preceding
                      Notes to Consolidated Financial Statements as they relate to
                      The Toledo
                      Edison Company are an integral part ofthese
                      balance
                      sheets.
   91
  **THE
                      TOLEDO EDISON COMPANY****CONSOLIDATED
                      STATEMENTS OF CASH FLOWS****(Unaudited)****Three
                      Months Ended****March
                      31,****2006**
                  
                  **2005*****(In
                      thousands)*****CASH
                      FLOWS FROM OPERATING ACTIVITIES:**Net
                      income
                  
                  $
                  29,006
                  
                  $
                  365Adjustments
                      to
                      reconcile net income to net cash from operating
                      activities-Provision
                      for
                      depreciation
                  
                  
                  8,097
                  
                  
                  14,680Amortization
                      of regulatory assets
                  
                  
                  24,456
                  
                  
                  34,865Deferral
                      of
                      new regulatory assets
                  
                  
                  (10,654
                  )
                  
                  (9,424
                  )Nuclear
                      fuel
                      and capital lease amortization
                  
                  
                  -
                  
                  
                  4,868Deferred
                      rents
                      and lease market valuation liability
                  
                  
                  (16,084
                  )
                  
                  (15,224
                  )Deferred
                      income taxes and investment tax credits, net
                  
                  
                  (8,453
                  )
                  
                  (1,387
                  )Deferred
                      purchased power costs
                  
                  
                  (3,002
                  )
                  
                  -Accrued
                      compensation and retirement benefits
                  
                  
                  1,110
                  
                  
                  (654
                  )Decrease
                      (increase) in operating assets-Receivables
                  
                  
                  (8,793
                  )
                  
                  41,475Materials
                      and
                      supplies
                  
                  
                  -
                  
                  
                  (6,489
                  )Prepayments
                      and other current assets
                  
                  
                  366
                  
                  
                  (56
                  )Increase
                      (decrease) in operating liabilities-Accounts
                      payable
                  
                  
                  (15,969
                  )
                  
                  6,935Accrued
                      taxes
                  
                  
                  20,401
                  
                  
                  (15,262
                  )Accrued
                      interest
                  
                  
                  (668
                  )
                  
                  853Electric
                      service prepayment programs
                  
                  
                  (2,231
                  )
                  
                  -Other
                  
                  
                  (121
                  )
                  
                  (1,989
                  )Net
                      cash
                      provided from operating activities
                  
                  
                  17,461
                  
                  
                  53,556**CASH
                      FLOWS FROM FINANCING ACTIVITIES:**New
                      Financing-Short-term
                      borrowings, net
                  
                  
                  55,539
                  
                  
                  -Redemptions
                      and Repayments-Preferred
                      stock
                  
                  
                  (30,000
                  )
                  
                  -Short-term
                      borrowings, net
                  
                  
                  -
                  
                  
                  (34,993
                  )Dividend
                      Payments-Common
                      stock
                  
                  
                  (25,000
                  )
                  
                  -Preferred
                      stock
                  
                  
                  (1,275
                  )
                  
                  (2,211
                  )Net
                      cash
                      used for financing activities
                  
                  
                  (736
                  )
                  
                  (37,204
                  )**CASH
                      FLOWS FROM INVESTING ACTIVITIES:**Property
                      additions
                  
                  
                  (15,044
                  )
                  
                  (17,919
                  )Loans
                      to
                      associated companies
                  
                  
                  (11,270
                  )
                  
                  (1,610
                  )Investments
                      in
                      lessor notes
                  
                  
                  9,335
                  
                  
                  11,928Proceeds
                      from
                      nuclear decommissioning trust fund sales
                  
                  
                  13,793
                  
                  
                  106,009Investments
                      in
                      nuclear decommissioning trust funds
                  
                  
                  (13,793
                  )
                  
                  (113,144
                  )Other
                  
                  
                  254
                  
                  
                  (1,616
                  )Net
                      cash
                      used for investing activities
                  
                  
                  (16,725
                  )
                  
                  (16,352
                  )Net
                      change in
                      cash and cash equivalents
                  
                  
                  -
                  
                  
                  -Cash
                      and cash
                      equivalents at beginning of period
                  
                  
                  15
                  
                  
                  15Cash
                      and cash
                      equivalents at end of period
                  
                  $
                  15
                  
                  $
                  15The
                      preceding
                      Notes to Consolidated Financial Statements as they relate to
                      The Toledo
                      Edison Company are an integralpart
                      of these
                      statements.
  92
   ***Report
        of Independent Registered Public Accounting Firm***
 
 
 
 
 
 
 
 
 
 To
        the Stockholder
        and Board of
 Directors
        of The
        Toledo Edison Company:
 
 We
        have reviewed the
        accompanying consolidated balance sheet of The Toledo Edison Company and
        its
        subsidiary as of March 31, 2006 and the related consolidated statements of
        income, comprehensive income and cash flows for each of the three-month periods
        ended March 31, 2006 and 2005. These interim financial statements are the
        responsibility of the Company’s management.
 
 We
        conducted our
        review in accordance with the standards of the Public Company Accounting
        Oversight Board (United States). A review of interim financial information
        consists principally of applying analytical procedures and making inquiries
        of
        persons responsible for financial and accounting matters. It is substantially
        less in scope than an audit conducted in accordance with the standards of
        the
        Public Company Accounting Oversight Board, the objective of which is the
        expression of an opinion regarding the financial statements taken as a whole.
        Accordingly, we do not express such an opinion.
 
 Based
        on our review,
        we are not aware of any material modifications that should be made to the
        accompanying consolidated interim financial statements for them to be in
        conformity with accounting principles generally accepted in the United States
        of
        America.
 
 We
        previously
        audited, in accordance with the standards of the Public Company Accounting
        Oversight Board (United States), the consolidated balance sheet as of December
        31, 2005, and the related consolidated statements of income, capitalization,
        common stockholder’s equity, preferred stock, cash flows and taxes for the year
        then ended (not presented herein), and in our report (which contained references
        to the Company’s change in its method of accounting for asset retirement
        obligations as of January 1, 2003 as discussed in Note 2(G) and Note 11 to
        those
        consolidated financial statements and the Company’s change in its method of
        accounting for the consolidation of variable interest entities as of
        December 31, 2003 as discussed in Note 6 to those consolidated financial
        statements) dated February 27, 2006, we expressed an unqualified opinion on
        those consolidated financial statements. In our opinion, the information
        set
        forth in the accompanying consolidated balance sheet as of December 31, 2005,
        is
        fairly stated in all material respects in relation to the consolidated balance
        sheet from which it has been derived.
 
 
 
 
 PricewaterhouseCoopers
        LLP
 Cleveland,
        Ohio
 May
        8,
        2006
 
 
  93
  **THE
        TOLEDO
        EDISON COMPANY**
 
 **MANAGEMENT’S
        DISCUSSION AND ANALYSIS OF**
 **RESULTS
        OF
        OPERATIONS AND FINANCIAL CONDITION**
 
  TE is a wholly owned electric utility subsidiary of FirstEnergy. TE conducts
        business in northwestern Ohio, providing regulated electric distribution
        services. TE also provides generation services to those customers electing
        to
        retain TE as their power supplier. TE’s power supply requirements are provided
        by FES - an affiliated company.
 
 **FirstEnergy
        Intra-System Generation Asset Transfers**
 
 On
        May 13,
        2005, Penn, and on May 18, 2005, the Ohio Companies, entered into certain
        agreements implementing a series of intra-system generation asset transfers
        that
        were completed in the fourth quarter of 2005. The asset transfers resulted
        in
        the respective undivided ownership interests of the Ohio Companies and Penn
        in
        FirstEnergy’s nuclear and non-nuclear generation assets being owned by NGC and
        FGCO, respectively. The generating plant interests transferred did not include
        TE's leasehold interests in certain of the plants that are currently subject
        to
        sale and leaseback arrangements with non-affiliates.
 
 On
        October 24,
        2005, TE completed the intra-system transfer of non-nuclear generation assets
        to
        FGCO. Prior to the transfer, FGCO, as lessee under a Master Facility Lease
        with
        the Ohio Companies and Penn, leased, operated and maintained the non-nuclear
        generation assets that it now owns. The asset transfers were consummated
        pursuant to FGCO's purchase option under the Master Facility Lease.
 
 On
        December 16,
        2005, TE completed the intra-system transfer of its ownership interests in
        the
        nuclear generation assets to NGC through a sale at net book value. FENOC
        continues to operate and maintain the nuclear generation assets.
 
 These
        transactions
        were undertaken pursuant to the Ohio Companies’ and Penn’s restructuring plans
        that were approved by the PUCO and the PPUC, respectively, under applicable
        Ohio
        and Pennsylvania electric utility restructuring legislation. Consistent with
        the
        restructuring plans, generation assets that had been owned by the Ohio Companies
        and Penn were required to be separated from the regulated delivery business
        of
        those companies through transfer to a separate corporate entity. The
        transactions essentially completed the divestitures contemplated by the
        restructuring plans by transferring the ownership interests to NGC and FGCO
        without impacting the operation of the plants.
 
 The
        transfers will affect TE’s near-term results with reductions in both revenues
        and expenses. Revenues are reduced due to the termination of certain
        arrangements with FES, under which TE previously sold its nuclear-generated
        KWH
        to FES and leased its non-nuclear generation assets to FGCO, a subsidiary
        of
        FES. TE’s expenses are lower due to the nuclear fuel and operating costs assumed
        by NGC as well as depreciation and property tax expenses assumed by FGCO
        and NGC
        related to the transferred generating assets. With respect to TE's retained
        leashold interests in the Bruce Mansfield Plant and Beaver Valley Unit 2,
        TE has
        continued the generation KWH sales arrangement with FES and continues to
        be
        obligated on the applicable portion of expenses related to those interests.
        In
        addition, TE receives interest income on associated company notes
        receivable from the transfer of its generation net assets. FES will continue
        to
        provide TE’s PLR requirements under revised purchased power arrangements for the
        three-year period beginning January 1, 2006 (see Outlook - Regulatory
        Matters).
  94
 
 The
        effects on TE’s
        results of operations in the first quarter of 2006 compared to the first
        quarter
        of 2005 from the generation asset transfers are summarized in the following
        table:
 
 **Intra-System
                  Generation Asset Transfers -****First
                  Quarter 2006 vs First Quarter 2005 Income Statement
                  Effects*****Increase
                  (Decrease)***
              
              ***(In
                  millions)***Operating
                  Revenues:Non-nuclear
                  generating units rent
              
              $
              (4
              )
(a)Nuclear
                  generated KWH sales
              
              
              (22
              )
(b)Total
                  -
                  Operating Revenues Effect
              
              
              (26
              )Operating
                  Expenses and Taxes:Fuel
                  costs -
                  nuclear
              
              
              (4
              )
(c)Nuclear
                  operating costs
              
              
              (39
              )
(c)Provision
                  for
                  depreciation
              
              
              (8
              )
(d)General
                  taxes
              
              
              (1
              )
(e)Income
                  taxes
              
              
              11
              (i)Total-
                  Operating Expenses and Taxes Effect
              
              
              (41
              )Operating
                  Income Effect
              
              
              15Other
                  Income:Interest
                  income from notes receivable
              
              
              4
              (f)Nuclear
                  decommissioning trust earnings
              
              
              (1
              )
(g)Income
                  taxes
              
              
              (1
              )
(i)Total-Other
                  Income Effect
              
              
              2Net
                  interest
                  Charges:Allowance
                  for
                  funds used during construction
              
              
              1Total-Net
                  Interest Charges Effect
              
              
              (1
              )
(h)Net
                  Income
                  Effect
              
              $
              18(a)
                  Elimination of non-nuclear generation assets lease to
                  FGCO.(b)
                  Reduction
                  of nuclear generated wholesale KWH sales to FES.(c)
                  Reduction
                  of nuclear fuel and operating costs.(d)
                  Reduction
                  of depreciation expense and asset retirement obligation accretion
                  related
                  togeneration
                  assets.(e)
                  Reduction
                  of property tax expense on generation assets.(f)
                  Interest
                  income on associated company notes receivable from the transfer
                  ofgeneration
                  net
                  assets.(g)
                  Reduction
                  of earnings on nuclear decommissioning trusts.(h)
                  Absence in
                  2006 of adjustment to 2005 allowance for borrowed funds used during
                  construction on generation assets transferred.(i)
                  Income tax
                  effect of the above adjustments.
 
 **Results
        of Operations**
 
 Earnings applicable to common stock in the first quarter of 2006 increased
        to
        $28 million from a loss of $2 million in the first quarter of 2005.
        This increase resulted primarily from reduced operating expenses and taxes,
        reduced net interest charges and increased other income, which was partially
        offset by lower operating revenues. These changes were principally from the
        effects of the generation asset transfer shown in the table above.
 
 *Operating
        Revenues*
 
 Operating revenues decreased by $24 million or 9.8% in the first quarter
        of 2006
        compared with the same period of 2005, primarily due to the generation asset
        transfer impact shown in the table above. Excluding the asset transfer effects,
        operating revenues increased $2 million due to a $27 million increase in
        retail
        generation sales revenues and a $6 million reduction in customer shopping
        incentives, partially offset by a $27 million decrease in distribution revenues
        and a $4 million decrease in wholesale sales to
        non-affiliates.
 
 Retail generation revenues increased $27 million with increases in all customer
        classes (residential - $16 million, commercial - $9 million and industrial
        - $2 million) due to higher unit prices and increased KWH sales. The higher
        unit
        prices reflected the rate stabilization charge and fuel cost recovery rider
        that
        became effective in January 2006 under the RCP. The increase in generation
        KWH
        sales (residential - 37.6%, commercial - 11.7% and industrial - 0.5%) primarily
        resulted from decreased customer shopping. The decreased shopping resulted
        from
        alternative energy suppliers terminating their supply arrangements with TE's
        shopping customers in the first quarter of 2006. Generation services provided
        by
        alternative suppliers as a percent of total sales deliveries in TE's franchise
        area decreased in all customer classes by the following percentage
        points :
        residential - 24.3%, commercial - 8.5% and industrial - 1.4%.
  95
 
 The lower non-affiliated wholesale revenues reflected a decrease in sales
        to
        municipal customers ($1 million) and a $3 million decrease due to the
        cessation of the MSG sales arrangements under TE’s transition plan in December
        2005. TE had been required to provide the MSG to non-affiliated alternative
        suppliers.
 
 Revenues from distribution throughput decreased by $27 million in the first
        quarter of 2006 from the corresponding quarter of 2005. The decrease in all
        customer sectors (residential - $12 million; commercial - $13 million; and
        industrial - $1 million) primarily reflected lower unit prices and
        decreased KWH deliveries. The lower unit prices reflected the completion
        of the
        generation-related transition cost recovery under TE’s transition plan in 2005,
        partially offset by the recovery of MISO costs beginning in 2006 (see Outlook
        -
        Regulatory Matters). The lower
        KWH
        distribution deliveries to residential and commercial customers reflected
        the
        impact of milder weather in the first quarter of 2006 compared to the same
        period of 2005.
 
 Under the Ohio transition plan, TE had provided incentives to customers to
        encourage switching to alternative energy providers, reducing TE's revenues.
        These revenue reductions, which were deferred for future recovery and did
        not
        affect current period earnings, ceased in 2006 and resulted in a $6 million
        change in revenues as discussed above. The deferred shopping incentives
        (Extended RTC) are currently being recovered under the RCP (see Outlook -
        Regulatory Matters).
 
 Changes in electric generation sales and distribution deliveries in the first
        quarter of 2006 from the first quarter of 2005 are summarized in the following
        table:
 
 **Changes
                  in KWH Sales****Increase
                  (Decrease)**Electric
                  Generation:Retail
              
              
              9.7
              %Wholesale:Non-Associated
                  Companies
              
              
              (40.3
              )%Associated
                  Companies(1)
              
              
              (57.7
              )%**Total
                  Electric Generation Sales**
              
              
              (23.1
              )%Distribution
                  Deliveries:Residential
              
              
              (1.3
              )%Commercial
              
              
              (3.8
              )%Industrial
              
              
              (0.9
              )%**Total
                  Distribution Deliveries**
              
              
              (2.0
              )%
 
 (1)  Change
        reflects
        impact of generation asset transfers.
 
 *Operating
        Expenses and Taxes*
 
 Total operating expenses and taxes decreased by $47 million in the first
        quarter
        of 2006 from the same quarter of 2005 principally due to the generation asset
        transfer effects as shown in the table above. Excluding the asset transfer
        effects, the following table presents changes from the prior year by expense
        category:
 
 **Operating
                  Expenses and Taxes - Changes****Increase
                  (Decrease)**
              
              ***(In
                  millions)***Purchased
                  power costs
              
              $
              (8
              )Nuclear
                  operating costs
              
              
              (2
              )Other
                  operating costs
              
              
              6Provision
                  for
                  depreciation
              
              
              2Amortization
                  of regulatory assets
              
              
              (10
              )Deferral
                  of
                  new regulatory assets
              
              
              (1
              )Income
                  taxes
              
              
              7**Total
                  operating expenses and taxes**
              
              **$**
              (6
              )
 
 Lower purchased power costs in the first quarter of 2006 compared to the
        first
        quarter of 2005 reflected lower unit prices associated with the new power
        supply
        agreement with FES and the RCP fuel cost deferrals of $3 million that began
        in 2006, partially offset by an increase in KWH purchased to meet the higher
        retail generation sales requirements. Decreased nuclear operating costs in
        the
        2006 period were due to lower costs associated with TE’s leasehold interest in
        Beaver Valley Unit 2. The first quarter of 2005 included costs related to
        preparations for the refueling outage which began April 4, 2005. Higher
        other operating costs reflect increased transmission expenses, primarily
        related
        to MISO Day 2 operations that began on April 1, 2005.
 
 Excluding the effects of the generation asset transfers, depreciation charges
        increased due to distribution plant additions.
  96
 
 Lower amortization of regulatory assets reflected the completion of
        generation-related transition cost recovery under TE’s transition plan,
        partially offset by the amortization of deferred MISO costs that are being
        recovered in 2006. As discussed above, the RCP transition costs amortization
        includes the amortization of the deferred shopping incentives, which began
        in
        2006. The net change in deferrals of new regulatory assets primarily resulted
        from the deferral of distribution costs and related interest ($6.1 million)
        under the RCP and deferrals of the 2006 MISO transmission costs and related
        interest ($1.7 million), partially offset by the termination of shopping
        incentive deferrals and interest ($6.4 million) in 2006.
 
 Increased income taxes in the first quarter of 2006 were primarily due to
        an
        increase in taxable income partially offset by a reduction in the tax rates
        due
        to the continuing phase-out of the income-based Ohio franchise tax.
 
 *Other
        Income*
 
 Other income increased $1.7 million in the first quarter of 2006, compared
        to
        the same period of 2005. Excluding the effects of the generation asset transfer,
        other income decreased $0.3 million. The decrease reflected the absence in
        2006
        of $2.4 million of interest income from a 2001 FGCO note (which had a balloon
        repayment in May 2005) partially offset by the accrual of a $1.6 million
        NRC fine related to the Davis-Besse Plant in the first quarter of
        2005.
 
 *Net
        Interest
        Charges*
 
 Excluding the effects of the asset transfer, net interest charges continued
        to
        trend lower, decreasing by $3 million in the first quarter of 2006 from the
        same period of 2005, reflecting redemptions and refinancing subsequent to
        the
        end of the first quarter of 2005.
 
 **Capital
        Resources and Liquidity**
 
 During 2006, TE expects to meet its contractual obligations with a combination
        of cash from operations and short-term credit arrangements. In connection
        with a
        plan to realign its capital structure, TE may issue up to $100 million of
        new long-term debt in 2006 with proceeds expected to fund a return of equity
        capital to FirstEnergy.
 
 *Changes
        in Cash
        Position*
 
 There was no change as of March 31, 2006 from December 31, 2005 in TE's
        cash and cash equivalents of $15,000.
 
 *Cash
        Flows From
        Operating Activities*
 
 Cash provided from operating activities during the first quarter of 2006,
        compared with the first quarter of 2005 were as follows:
 
 **Three
                  Months Ended**
                **March
                  31,****Operating
                  Cash Flows**
              
              **2006**
              
              **2005*****(In
                  millions)***Cash
                  earnings(1)
              
              $
              21
              
              $
              28Working
                  capital and other
              
              
              (3
              )
              
              26Net
                  cash
                  provided from operating activities
              
              $
              18
              
              $
              54
 
 (1)  Cash
        earnings is a
        non-GAAP measure (see reconciliation below).
  97
 
 Cash earnings (in the table above) are not a measure of performance
        calculated in accordance with GAAP. TE believes that cash
        earnings are 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**
                **March
                  31,****Reconciliation
                  of Cash Earnings**
              
              **2006**
              
              **2005*****(In
                  millions)***Net
                  Income
                  (GAAP)
              
              $
              29
              
              $
              -Non-Cash
                  Charges (Credits):Provision
                  for
                  depreciation
              
              
              8
              
              
              15Amortization
                  of regulatory assets
              
              
              24
              
              
              35Deferral
                  of
                  new regulatory assets
              
              
              (11
              )
              
              (9
              )Nuclear
                  fuel
                  and capital lease amortization
              
              
              -
              
              
              5Amortization
                  of electric service obligation
              
              
              (2
              )
              
              -Deferred
                  rents
                  and lease market valuation liability
              
              
              (16
              )
              
              (15
              )Deferred
                  income taxes and investment tax credits, net
              
              
              (8
              )
              
              (2
              )Deferred
                  purchased power costs
              
              
              (3
              )
              
              -Accrued
                  compensation and retirement benefits
              
              
              -
              
              
              (1
              )Cash
                  earnings
                  (Non-GAAP)
              
              $
              21
              
              $
              28
 
 Net cash provided from operating activities decreased by $36 million in the
        first quarter of 2006 from the first quarter of 2005 as a result of a $7
        million
        decrease in cash earnings described above under “Results of Operations” and a
        $29 million decrease from working capital. The change in working capital
        was primarily due to a $50 million decrease in cash provided from the
        settlement of receivables and $23 million of increased outflows for accounts
        payable, partially offset by changes in accrued taxes of
        $36 million.
 
 *Cash
        Flows From
        Financing Activities*
  Net cash used for financing activities decreased by $36 million in the first
        quarter of 2006, as compared to the same period of 2005. The decrease resulted
        from a $91 million increase in net short-term borrowings, partially offset
        by
        $30 million of preferred stock redemptions and $25 million of common stock
        dividends to FirstEnergy in 2006.
 
 On January 20, 2006, TE redeemed all 1.2 million of its outstanding shares
        of
        Adjustable Preferred Rate Series B preferred stock at $25.00 per share, plus
        accrued dividends to the date of redemption.
 
 TE had $60 million of cash and temporary investments (which included short-term
        notes receivable from associated companies) and $120 million of short-term
        indebtedness as of March 31, 2006. TE has authorization from the PUCO to
        incur
        short-term debt of up to $500 million (including through the available bank
        facility and the utility money pool described below). As of March 31, 2006,
        TE had the capability to issue $628 million of additional FMB on the basis
        of
        property additions and retired bonds under the terms of its mortgage indenture.
        Based upon applicable earnings coverage tests, TE could issue up to $1.5
        billion
        of preferred stock (assuming no additional debt) was issued as of March 31,
        2006.
 
 TE, FirstEnergy, OE, Penn, CEI, JCP&L, Met-Ed, Penelec, FES and ATSI, as
        Borrowers, have entered into a syndicated $2 billion five-year revolving
        credit facility with a syndicate of banks that expires in June 2010. 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 expiration
        date, as the same may be extended. TE’s borrowing limit under the facility is
        $250 million subject to applicable regulatory approval.
 
 Under the revolving credit facility, borrowers may request the issuance of
        letters of credit expiring up to one year from the date of issuance. The
        stated
        amount of outstanding letters of credit will count against total commitments
        available under the facility and against the applicable borrower’s borrowing
        sub-limit.
 
 The revolving credit facility contains financial covenants requiring each
        borrower to maintain a consolidated debt to total capitalization ratio of
        no
        more than 65%. As of March 31, 2006, TE's debt to total capitalization, as
        defined under the revolving credit facility, was 31%.
 
 The facility does not contain any provisions that either restrict TE's ability
        to borrow or accelerate repayment of outstanding advances as a result of
        any
        change in its credit ratings. Pricing is defined in “pricing grids”, whereby the
        cost of funds borrowed under the facility is related to TE's credit
        ratings.
  98
 
 TE has the ability to borrow from its regulated affiliates and FirstEnergy
        to
        meet its short-term working capital requirements. FESC administers this money
        pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries.
        Companies receiving a loan under the money pool agreements must repay the
        principal, together with accrued interest, within 364 days of borrowing the
        funds. The rate of interest is the same for each company receiving a loan
        from
        the pool and is based on the average cost of funds available through the
        pool.
        The average interest rate for borrowings in the first quarter of 2006 was
        4.58%.
 
 TE’s access to the capital markets and the costs of financing are dependent
        on
        the ratings of its securities and the securities of FirstEnergy. The ratings
        outlook from S&P on all securities is stable. The ratings outlook from
        Moody’s and Fitch on all securities is positive.
 
 In
        April 2006,
        pollution control notes that were formerly obligations of TE were refinanced
        and
        became obligations of FGCO and NGC. The proceeds from the refinancings were
        used
        to repay a portion of their associated company notes payable to TE.  With
        those repayments, TE redeemed pollution control notes in the aggregate principal
        amount of $54 million having variable interest rates.
 
 *Cash
        Flows From
        Investing Activities*
 
 Net cash used for investing activities was effectively unchanged in the first
        quarter of 2006 compared to the same period of 2005. Decreases in property
        additions and net activity for the nuclear decommissioning trust funds were
        offset by increased loans to associated companies.
  TE’s capital spending for the last three quarters of 2006 is expected to be
        about $47 million. These cash requirements are expected to be satisfied
        from a combination of internal cash, funds raised in the long-term capital
        markets (up to $100 million) and short-term credit arrangements. TE’s
        capital spending for the period 2006-2010 is expected to be about
        $236 million of which approximately $62 million applies to 2006.
 
 **Off-Balance
        Sheet Arrangements**
 
 Obligations not included on TE’s Consolidated Balance Sheet primarily consist of
        sale and leaseback arrangements involving the Bruce Mansfield Plant and Beaver
        Valley Unit 2. As of March 31, 2006, the present value of these operating
        lease commitments, net of trust investments, totaled $535 million.
 
 **OUTLOOK**
  The
        electric
        industry continues to transition to a more competitive environment and all
        of
        TE’s customers can select alternative energy suppliers. TE continues to deliver
        power to residential homes and businesses through its existing distribution
        system, which remains regulated. Customer rates have been restructured into
        separate components to support customer choice. TE has a continuing
        responsibility to provide power to those customers not choosing to receive
        power
        from an alternative energy supplier subject to certain limits.
 
 *Regulatory
        Matters*
  Regulatory
        assets
        are costs which have been authorized by the PUCO and the FERC for recovery
        from
        customers in future periods or for which authorization is probable. Without
        the
        probability of such authorization, costs currently recorded as regulatory
        assets
        would have been charged to income as incurred. All regulatory assets are
        expected to be recovered under the provisions of TE’s regulatory plans. TE’s
        regulatory assets as of March 31, 2006 and December 31, 2005 were
        $276 million and $287 million, respectively.
 
 On October 21, 2003 the Ohio Companies filed the RSP case with the PUCO.
        On
        August 5, 2004, the Ohio Companies accepted the RSP as modified and approved
        by
        the PUCO in an August 4, 2004 Entry on Rehearing, subject to a CBP. The RSP
        was
        intended to establish generation service rates beginning January 1, 2006,
        in response to 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 arguments on the appeals. On May 3, 2006, the Supreme
        Court of Ohio issued an opinion affirming that order with respect to the
        approval of the rate stabilization charge, approval of the shopping credits,
        the
        grant of interest on shopping credit incentive deferral amounts, and approval
        of
        FirstEnergy’s financial separation plan. It remanded the approval of the RSP
        pricing back to the PUCO for further consideration of the issue as to whether
        the RSP, as adopted by the PUCO, provided for sufficient customer participation
        in the competitive marketplace.
  99
 
 Under provisions of the RSP, the PUCO had required the Ohio Companies to
        undertake a CBP to secure generation and allow for customer pricing
        participation in the competitive marketplace. Any acceptance of future
        competitive bid results would terminate the RSP pricing, with no accounting
        impacts to the RSP, and not until 12 months after the PUCO authorizes such
        termination. On December 9, 2004, the PUCO rejected the auction price
        results from the CBP for the generation supply period beginning January 1,
        2006
        and issued an entry stating that the pricing under the approved revised RSP
        would take effect on January 1, 2006. On February 23, 2006 the CBP
        auction manager, National Economic Research Associates, notified the PUCO
        that a
        subsequent CBP to potentially provide firm generation service for the Ohio
        Companies' 2007 and 2008 actual load requirements could not proceed due to
        lack
        of interest, as there were no bidder applications submitted. Additionally,
        on
        March 20, 2006, the PUCO denied applications for rehearing filed by various
        parties regarding the PUCO's rules for the CBP. The above May 3, 2006
        Supreme Court of Ohio opinion may require the PUCO to reconsider this
        customer pricing process.
 
 On
        January 4, 2006,
        the PUCO approved, with modifications, TE's RCP to supplement the RSP to
        provide customers with more certain rate levels than otherwise available
        under
        the RSP during the plan period. Major provisions of the RCP
        include:
 
 ·
              Maintaining
                  the existing level of base distribution rates through December 31,
                  2008 for TE;
 
 ·
              Deferring
                  and
                  capitalizing for future recovery (over a 25-year period) with carrying
                  charges certain distribution costs to be incurred by all the Ohio
                  Companies during the period January 1, 2006 through December 31,
                  2008, not to exceed $150 million in each of the three
                  years;
 
 ·
              Adjusting
                  the
                  RTC and extended RTC recovery periods and rate levels so that full
                  recovery of authorized costs will occur as of December 31, 2008 for
                  TE;
 
 ·
              Reducing
                  the
                  deferred shopping incentive balances as of January 1, 2006 by up to
                  $45 million for TE by accelerating the application of its accumulated
                  cost of removal regulatory liability;
                  and
 
 ·
              Recovering
                  increased fuel costs (compared to a 2002 baseline) of up to $75
                  million,
                  $77 million, and $79 million, in 2006, 2007, and 2008,
                  respectively, from all OE and TE distribution and transmission
                  customers
                  through a fuel recovery mechanism. The Ohio Companies may defer
                  and
                  capitalize (for recovery over a 25-year period) increased fuel
                  costs above
                  the amount collected through the fuel recovery mechanism (in lieu
                  of
                  implementation of the GCAF rider).
 
 The
        following table
        provides the estimated amortization of regulatory transition costs and deferred
        shopping incentives (including associated carrying charges) under the RCP
        for
        the period 2006 through 2008:
 
 **Amortization****Period**
              
              **Amortization*****(In
                  millions)***2006
              
              $
              832007
              
              
              902008
              
              
              108**Total
                  Amortization**
              
              **$**
              **281**
 
 The
        PUCO’s January
        4, 2006 approval of the RCP also included approval of the Ohio
        Companies’ supplemental
        stipulation which was filed with the PUCO on November 4, 2005 and which was
        an
        additional component of the RCP filed on September 9, 2005. On
        January 10, 2006, the Ohio Companies filed a Motion for Clarification of
        the PUCO order approving the RCP. The Ohio Companies sought clarity on issues
        related to distribution deferrals, including requirements of the review process,
        timing for recognizing certain deferrals and definitions of the types of
        qualified expenditures. The Ohio Companies also sought confirmation that
        the
        list of deferrable distribution expenditures originally included in the revised
        stipulation fall within the PUCO order definition of qualified expenditures.
        On
        January 25, 2006, the PUCO issued an Entry on Rehearing granting in part,
        and denying in part, the Ohio Companies’ previous requests and clarifying issues
        referred to above. The PUCO granted the Ohio Companies’ requests to:
  ·
                Recognize
                    fuel
                    and distribution deferrals commencing January 1,
                    2006;·
                Recognize
                    distribution deferrals on a monthly basis prior to review by
                    the PUCO
                    Staff;·
                Clarify
                    that
                    the types of distribution expenditures included in the Supplemental
                    Stipulation may be deferred; and·
                Clarify
                    that
                    distribution expenditures do not have to be “accelerated” in order to be
                    deferred.
   100
  The
        PUCO approved the Ohio Companies’ methodology for determining distribution
        deferral amounts, but denied the Motion in that the PUCO Staff must verify
        the
        level of distribution expenditures contained in current rates, as opposed
        to
        simply accepting the amounts contained in the Ohio Companies’ Motion. On
        February 3, 2006, several other parties filed applications for rehearing
        on the
        PUCO's January 4, 2006 Order. The Ohio Companies responded to the
        applications for rehearing on February 13, 2006. In an Entry on Rehearing
        issued by the PUCO on March 1, 2006, all motions for rehearing were denied.
        Certain of these parties have subsequently filed their notices of appeal
        with
        the Supreme Court of Ohio alleging various errors made by the PUCO in its
        order
        approving the RCP.
 
 On
        December 30,
        2004, TE filed with the PUCO two applications related to the recovery of
        transmission and ancillary service related costs. The first application sought
        recovery of these costs beginning January 1, 2006. TE requested that these
        costs be recovered through a rider that would be effective on January 1,
        2006 and adjusted each July 1 thereafter. The parties reached a settlement
        agreement that was approved by the PUCO on August 31, 2005. The incremental
        transmission and ancillary service revenues expected to be recovered from
        January through June 2006 are approximately $8 million. This amount
        includes the recovery of the 2005 deferred MISO expenses as described below.
        On
        May 1, 2006, TE filed a modification to the rider to 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 TE 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 TE to accrue
        carrying charges on the deferred balances. On August 31, 2005, the OCC
        appealed the PUCO's decision. All briefs have been filed. On March 20, 2006,
        the
        Ohio Supreme Court, on its own motion, consolidated the OCC's appeal of TE's
        case with a similar case involving Dayton Power & Light Company. Oral
        argument is currently scheduled for May 10, 2006.
 
 On
        January 20,
        2006 the OCC sought rehearing of the PUCO approval of the recovery of deferred
        costs through the rider during the period January 1, 2006 through June 30,
        2006. The PUCO denied the OCC's application on February 6, 2006. On March
        23, 2006, the OCC appealed the PUCO's order to the Ohio Supreme Court. The
        OCC's
        brief is expected to be filed during the second quarter of 2006. The briefs
        of the PUCO and TE will be due within thirty days of the OCC's filing. On
        March
        27, 2006, the OCC filed a motion to consolidate this appeal with the deferral
        appeals discussed above and to postpone oral arguments in the deferral appeal
        until after all briefs are filed in this most recent appeal of the rider
        recovery mechanism. On
        April 18, 2006,
        the Court denied both parts of the motion but on its own motion consolidated
        the
        OCC's appeal of TE's case with a similar case of Dayton Power & Light
        Company and stayed briefing on these appeals.
 
 On
        November 1, 2005,
        FES filed two power sales agreements for approval with the FERC. One power
        sales
        agreement provided for FES to provide the PLR requirements of the Ohio Companies
        at a price equal to the retail generation rates approved by the PUCO for
        a
        period of three years beginning January 1, 2006. The Ohio Companies will be
        relieved of their obligation to obtain PLR power requirements from FES if
        the
        Ohio competitive bid process results in a lower price for retail customers.
        A
        similar power sales agreement between FES and Penn permits Penn to obtain
        its
        PLR power requirements from FES at a fixed price equal to the retail generation
        price during 2006. The PPUC approved Penn's plan with modifications on April
        20,
        2006 to use an RFP process to obtain its power supply requirements after
        2006.
 
 On
        December 29,
        2005, the FERC issued an order setting the two power sales agreements for
        hearing. The order criticized the Ohio competitive bid process, and required
        FES
        to submit additional evidence in support of the reasonableness of the prices
        charged in the power sales agreements. A pre-hearing conference was held
        on
        January 18, 2006 to determine the hearing schedule in this case. FES
        expects an initial decision to be issued in this case in late January 2007,
        as a
        result of the April 20, 2006 extension of the procedural schedule. The outcome
        of this proceeding cannot be predicted. FES has sought rehearing of the
        December 29, 2005 order and the FERC granted rehearing for future
        consideration on March 1, 2006.
 
 See
        Note 11 to
        the consolidated financial statements for further details and a complete
        discussion of regulatory matters in Ohio.
 
 *Environmental
        Matters*
 
 TE
        accrues environmental liabilities when it is probable that it has an obligation
        for such costs and can reasonably estimate the amount of such costs. Unasserted
        claims are reflected in TE’s determination of environmental liabilities and are
        accrued in the period that they are both probable and reasonably
        estimable.
  101
   *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 March 31, 2006, based on
        estimates of the total costs of cleanup, TE’s proportionate responsibility for
        such costs and the financial ability of other unaffiliated entities to pay.
        Included in Other Noncurrent Liabilities are accrued liabilities aggregating
        approximately $0.2 million as of March 31, 2006.
 
 See
        Note 10(B)
        to the consolidated financial statements for further details and a complete
        discussion of environmental matters.
 
 *Other
        Legal
        Proceedings*
 
 There
        are various
        lawsuits, claims (including claims for asbestos exposure) and proceedings
        related to TE’s normal business operations pending against TE. The other
        potentially material items not otherwise discussed above are described
        below.
 
 *Power
        Outages
        and Related Litigation-*
 
 On
        August 14,
        2003, various states and parts of southern Canada experienced widespread
        power
        outages. The outages affected approximately 1.4 million customers in
        FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s
        final report in April 2004 on the outages concluded, among other things,
        that
        the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically,
        the
        final report concluded, among other things, that the initiation of the
        August 14, 2003 power outages resulted from an alleged failure of both
        FirstEnergy and ECAR to assess and understand perceived inadequacies within
        the
        FirstEnergy system; inadequate situational awareness of the developing
        conditions; and a perceived failure to adequately manage tree growth in certain
        transmission rights of way. The Task Force also concluded that there was
        a
        failure of the interconnected grid's reliability organizations (MISO and
        PJM) to
        provide effective real-time diagnostic support. The final report is publicly
        available through the Department of Energy’s 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
        March 31, 2006 for any expenditure 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 Company, Inc. as well) for claims paid to insureds
        for
        damages allegedly arising as a result of the loss of power on August 14,
        2003. The listed insureds in these cases, in many instances, are not customers
        of any FirstEnergy company. The fourth case involves the claim of a non-customer
        seeking reimbursement for losses incurred when its store was burglarized
        on
        August 14, 2003. On
        March 7,
        2006, the PUCO issued a ruling applicable to all pending cases. Among its
        various rulings, the PUCO consolidated all of the pending outage cases for
        hearing; limited the litigation to service-related claims by customers of
        the
        Ohio operating companies; dismissed FirstEnergy Corp. as a defendant; ruled
        that
        the U.S.-Canada Power System Outage Task Force Report was not admissible
        into
        evidence; and gave the plaintiffs additional time to amend their complaints
        to
        otherwise comply with the PUCO's underlying order. The plaintiffs in
        one case have since filed an amended complaint. The named FirstEnergy companies
        have answered and also have filed a motion to dismiss the action, which is
        pending. Also, most complainants, along with the FirstEnergy companies, filed
        applications for rehearing with the PUCO over various rulings contained in
        the
        March 7, 2006 order. On April 26, 2006, the PUCO granted rehearing to allow
        the
        insurance company claimants, as insurers, to prosecute their claims in their
        name so long as they also identify the underlying insured entities and the
        Ohio
        utilities which provide their service. The PUCO denied all other motions
        for
        rehearing. No estimate of potential liability is available for any of these
        cases. 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.
        Following the PUCO's March 7, 2006 order, that action was voluntarily
        dismissed by the claimants.
   102
  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 and results of operations.
 
 *Other
        Legal
        Matters-*
  On
        October 20,
        2004, FirstEnergy was notified by the SEC that the previously disclosed informal
        inquiry initiated by the SEC's Division of Enforcement in September 2003
        relating to the restatements in August 2003 of previously reported results
        by
        FirstEnergy and the Ohio Companies, and the Davis-Besse extended outage,
        have
        become the subject of a formal order of investigation. The SEC's formal order
        of
        investigation also encompasses issues raised during the SEC's examination
        of
        FirstEnergy and the Companies under PUHCA. Concurrent with this notification,
        FirstEnergy received a subpoena asking for background documents and documents
        related to the restatements and Davis-Besse issues. On December 30, 2004,
        FirstEnergy received a subpoena asking for documents relating to issues raised
        during the SEC's PUHCA examination. On August 24, 2005 additional
        information was requested regarding Davis-Besse related disclosures, which
        FirstEnergy has provided. FirstEnergy has cooperated fully with the informal
        inquiry and will continue to do so with the formal investigation.
 
 The
        City of Huron
        filed a complaint against OE with the PUCO challenging the ability of electric
        distribution utilities to collect transition charges from a customer of a
        newly
        formed municipal electric utility. The complaint was filed on May 28, 2003,
        and OE timely filed its response on June 30, 2003. In a related filing, the
        Ohio Companies filed for approval with the PUCO 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 decide 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 10(C)
        to the consolidated financial statements for further details and a complete
        discussion of these and other legal proceedings.
 
 **New
        Accounting Standards and Interpretations**
 
 *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. This EITF issue will not have a material impact on TE's
        financial results.
  103
  
 *SFAS
        155 -
“Accounting for Certain Hybrid Financial Instruments-an amendment of FASB
        Statements No. 133 and 140”*
 
 In February 2006, the FASB
        issued SFAS 155
        which amends SFAS 133 “Accounting for Derivative Instruments and Hedging
        Activities,” (SFAS 133) and SFAS 140 “Accounting for Transfers and Servicing of
        Financial Assets and Extinguishments of Liabilities.” This Statement permits
        fair value remeasurement for any hybrid financial instrument that contains
        an
        embedded derivative that otherwise would require bifurcation, clarifies which
        interest-only strips and principal-only strips are not subject to the
        requirements of SFAS 133, establishes a requirement to evaluate interests
        in
        securitized financial assets to identify interests that are freestanding
        derivatives or that are hybrid financial instruments that contain an embedded
        derivative requiring bifurcation, clarifies that concentrations of credit
        risk
        in the form of subordination are not embedded derivatives and amends SFAS
        140 to
        eliminate the prohibition on a qualifying special-purpose entity from holding
        a
        derivative financial instrument that pertains to a beneficial interest other
        than another derivative instrument. This Statement is effective for all
        financial instruments acquired or issued beginning January 1, 2007. TE is
        currently evaluating the impact of this Statement on its financial
        statements.
 
  104
  **PENNSYLVANIA
                    POWER COMPANY****CONSOLIDATED
                    STATEMENTS OF INCOME AND COMPREHENSIVE
                    INCOME****(Unaudited)****Three
                    Months Ended****March
                    31,****2006**
                
                **2005****STATEMENTS
                    OF INCOME**
                
                ***(In
                    thousands)*****OPERATING
                    REVENUES**
                
                $
                82,719
                
                $
                134,484**OPERATING
                    EXPENSES AND TAXES:**Fuel
                
                
                -
                
                
                5,620Purchased
                    power
                
                
                54,756
                
                
                46,980Nuclear
                    operating costs
                
                
                -
                
                
                19,948Other
                    operating costs
                
                
                14,204
                
                
                12,768Provision
                    for
                    depreciation
                
                
                2,431
                
                
                3,694Amortization
                    of regulatory assets
                
                
                3,411
                
                
                9,882General
                    taxes
                
                
                5,834
                
                
                6,472Income
                    taxes
                    (benefit)
                
                
                (251
                )
                
                12,421Total
                    operating expenses and taxes
                
                
                80,385
                
                
                117,785**OPERATING
                    INCOME**
                
                
                2,334
                
                
                16,699**OTHER
                    INCOME (EXPENSE) (net of income taxes)**
                
                
                2,333
                
                
                (745
                )**NET
                    INTEREST CHARGES:**Interest
                    on
                    long term debt
                
                
                1,246
                
                
                2,054Allowance
                    for
                    borrowed funds used during construction
                
                
                (34
                )
                
                (1,367
                )Other
                    interest
                    expense
                
                
                2,709
                
                
                265Net
                    interest
                    charges
                
                
                3,921
                
                
                952**NET
                    INCOME**
                
                
                746
                
                
                15,002**PREFERRED
                    STOCK DIVIDEND REQUIREMENTS**
                
                
                156
                
                
                640**EARNINGS
                    ON COMMON STOCK**
                
                $
                590
                
                $
                14,362**STATEMENTS
                    OF COMPREHENSIVE INCOME****NET
                    INCOME**
                
                $
                746
                
                $
                15,002**OTHER
                    COMPREHENSIVE INCOME**
                
                
                -
                
                
                -**TOTAL
                    COMPREHENSIVE INCOME**
                
                $
                746
                
                $
                15,002The
                    preceding
                    Notes to Consolidated Financial Statements as they relate to
                    Pennsylvania
                    Power Company arean
                    integral
                    part of these statements.
   105
  **PENNSYLVANIA
                      POWER COMPANY****CONSOLIDATED
                      BALANCE SHEETS****(Unaudited)****March
                      31,**
                  
                  **December
                      31,****2006**
                  
                  **2005*****(In
                      thousands)*****ASSETS****UTILITY
                      PLANT:**In
                      service
                  
                  $
                  364,663
                  
                  $
                  359,069Less
                      -
                      Accumulated provision for depreciation
                  
                  
                  130,346
                  
                  
                  129,118234,317
                  
                  
                  229,951Construction
                      work in progress-Electric
                      plant
                  
                  
                  2,301
                  
                  
                  3,775236,618
                  
                  
                  233,726**OTHER
                      PROPERTY AND INVESTMENTS:**Long-term
                      notes receivable from associated companies
                  
                  
                  283,125
                  
                  
                  283,248Other
                  
                  
                  351
                  
                  
                  351283,476
                  
                  
                  283,599**CURRENT
                      ASSETS:**Cash
                      and cash
                      equivalents
                  
                  
                  41
                  
                  
                  24Notes
                      receivable from associated companies
                  
                  
                  10,833
                  
                  
                  1,699Receivables
                      -Customers
                      (less accumulated provisions of $1,092,000 and $1,087,000,respectively,
                      for uncollectible accounts)
                  
                  
                  39,510
                  
                  
                  44,555Associated
                      companies
                  
                  
                  80,186
                  
                  
                  115,441Other
                  
                  
                  1,239
                  
                  
                  2,889Prepayments
                      and other
                  
                  
                  22,561
                  
                  
                  86,995154,370
                  
                  
                  251,603**DEFERRED
                      CHARGES AND OTHER ASSETS:**Prepaid
                      pension costs
                  
                  
                  42,649
                  
                  
                  42,243Other
                  
                  
                  1,955
                  
                  
                  3,82944,604
                  
                  
                  46,072$
                  719,068
                  
                  $
                  815,000**CAPITALIZATION
                      AND LIABILITIES****CAPITALIZATION:**Common
                      stockholder's equityCommon
                      stock,
                      $30 par value, authorized 6,500,000 shares-6,290,000
                      shares outstanding
                  
                  $
                  188,700
                  
                  $
                  188,700Other
                      paid in
                      capital
                  
                  
                  71,136
                  
                  
                  71,136Retained
                      earnings
                  
                  
                  37,687
                  
                  
                  37,097Preferred
                      stock
                  
                  
                  14,105
                  
                  
                  14,105Long-term
                      debt
                      and other long-term obligations
                  
                  
                  123,807
                  
                  
                  130,677435,435
                  
                  
                  441,715**CURRENT
                      LIABILITIES:**Currently
                      payable long-term debt
                  
                  
                  22,424
                  
                  
                  69,524Short-term
                      borrowings -Associated
                      companies
                  
                  
                  -
                  
                  
                  12,703Other
                  
                  
                  19,000
                  
                  
                  -Accounts
                      payable -Associated
                      companies
                  
                  
                  20,538
                  
                  
                  73,444Other
                  
                  
                  1,666
                  
                  
                  1,828Accrued
                      taxes
                  
                  
                  32,806
                  
                  
                  28,632Accrued
                      interest
                  
                  
                  1,059
                  
                  
                  1,877Other
                  
                  
                  6,620
                  
                  
                  8,086104,113
                  
                  
                  196,094**NONCURRENT
                      LIABILITIES:**Accumulated
                      deferred income taxes
                  
                  
                  63,683
                  
                  
                  66,576Retirement
                      benefits
                  
                  
                  46,429
                  
                  
                  45,967Regulatory
                      liabilities
                  
                  
                  63,781
                  
                  
                  58,637Other
                  
                  
                  5,627
                  
                  
                  6,011179,520
                  
                  
                  177,191**COMMITMENTS
                      AND CONTINGENCIES (Note 10)**$
                  719,068
                  
                  $
                  815,000The
                      preceding
                      Notes to Consolidated Financial Statements as they relate to
                      Pennsylvania
                      Power Company are an integral part of these balance
                      sheets.
    106
   **PENNSYLVANIA
                      POWER COMPANY****CONSOLIDATED
                      STATEMENTS OF CASH FLOWS****(Unaudited)****Three
                      Months Ended****March
                      31,****2006**
                  
                  **2005*****(In
                      thousands)*****CASH
                      FLOWS FROM OPERATING ACTIVITIES:**Net
                      income
                  
                  $
                  746
                  
                  $
                  15,002Adjustments
                      to
                      reconcile net income to net cash from operating
                      activities-Provision
                      for
                      depreciation
                  
                  
                  2,431
                  
                  
                  3,694Amortization
                      of regulatory assets
                  
                  
                  3,411
                  
                  
                  9,882Nuclear
                      fuel
                      and other amortization
                  
                  
                  -
                  
                  
                  4,140Deferred
                      income taxes and investment tax credits, net
                  
                  
                  (2,348
                  )
                  
                  (2,311
                  )Decrease
                      (increase) in operating assets-Receivables
                  
                  
                  41,950
                  
                  
                  11,892Materials
                      and
                      supplies
                  
                  
                  -
                  
                  
                  218Prepayments
                      and other current assets
                  
                  
                  64,433
                  
                  
                  (13,481
                  )Increase
                      (decrease) in operating liabilities-Accounts
                      payable
                  
                  
                  (53,068
                  )
                  
                  (2,890
                  )Accrued
                      taxes
                  
                  
                  4,175
                  
                  
                  11,420Accrued
                      interest
                  
                  
                  (819
                  )
                  
                  (258
                  )Other
                  
                  
                  1,607
                  
                  
                  778Net
                      cash
                      provided from operating activities
                  
                  
                  62,518
                  
                  
                  38,086**CASH
                      FLOWS FROM FINANCING ACTIVITIES:**New
                      Financing-Short-term
                      borrowings, net
                  
                  
                  6,297
                  
                  
                  -Redemptions
                      and Repayments-Long-term
                      debt
                  
                  
                  (54,462
                  )
                  
                  -Short-term
                      borrowings, net
                  
                  
                  -
                  
                  
                  (1,208
                  )Dividend
                      Payments-Common
                      stock
                  
                  
                  -
                  
                  
                  (8,000
                  )Preferred
                      stock
                  
                  
                  (156
                  )
                  
                  (640
                  )Net
                      cash
                      used for financing activities
                  
                  
                  (48,321
                  )
                  
                  (9,848
                  )**CASH
                      FLOWS FROM INVESTING ACTIVITIES:**Property
                      additions
                  
                  
                  (5,114
                  )
                  
                  (28,522
                  )Proceeds
                      from
                      nuclear decommissioning trust fund sales
                  
                  
                  -
                  
                  
                  13,703Investments
                      in
                      nuclear decommissioning trust funds
                  
                  
                  -
                  
                  
                  (14,102
                  )Loans
                      to
                      associated companies
                  
                  
                  (9,010
                  )
                  
                  (19
                  )Other
                  
                  
                  (56
                  )
                  
                  702Net
                      cash
                      used for investing activities
                  
                  
                  (14,180
                  )
                  
                  (28,238
                  )Net
                      change in
                      cash and cash equivalents
                  
                  
                  17
                  
                  
                  -Cash
                      and cash
                      equivalents at beginning of period
                  
                  
                  24
                  
                  
                  38Cash
                      and cash
                      equivalents at end of period
                  
                  $
                  41
                  
                  $
                  38The
                      preceding
                      Notes to Consolidated Financial Statements as they relate to
                      Pennsylvania
                      Power Company are an integralpart
                      of these
                      statements.
  107
   ***Report
        of Independent Registered Public Accounting Firm***
 
 
 
 
 
 
 
 
 
 To
        the Stockholder
        and Board of
 Directors
        of
        Pennsylvania Power Company:
 
 We
        have reviewed the
        accompanying consolidated balance sheet of Pennsylvania Power Company and
        its
        subsidiary as of March 31, 2006 and the related consolidated statements of
        income, comprehensive income and cash flows for each of the three-month periods
        ended March 31, 2006 and 2005. These interim financial statements are the
        responsibility of the Company’s management.
 
 We
        conducted our
        review in accordance with the standards of the Public Company Accounting
        Oversight Board (United States). A review of interim financial information
        consists principally of applying analytical procedures and making inquiries
        of
        persons responsible for financial and accounting matters. It is substantially
        less in scope than an audit conducted in accordance with the standards of
        the
        Public Company Accounting Oversight Board, the objective of which is the
        expression of an opinion regarding the financial statements taken as a whole.
        Accordingly, we do not express such an opinion.
 
 Based
        on our review,
        we are not aware of any material modifications that should be made to the
        accompanying consolidated interim financial statements for them to be in
        conformity with accounting principles generally accepted in the United States
        of
        America.
 
 We
        previously
        audited, in accordance with the standards of the Public Company Accounting
        Oversight Board (United States), the consolidated balance sheet as of December
        31, 2005, and the related consolidated statements of income, capitalization,
        common stockholder’s equity, preferred stock, cash flows and taxes for the year
        then ended (not presented herein), and in our report (which contained references
        to the Company’s change in its method of accounting for asset retirement
        obligations as of January 1, 2003 as discussed in Note 2(G) and Note 8 to
        those
        consolidated financial statements) dated February 27, 2006, we expressed
        an
        unqualified opinion on those consolidated financial statements. In our opinion,
        the information set forth in the accompanying consolidated balance sheet
        as of
        December 31, 2005, is fairly stated in all material respects in relation to
        the consolidated balance sheet from which it has been derived.
 
 
 
 
 PricewaterhouseCoopers
        LLP
 Cleveland,
        Ohio
 May
        8,
        2006
 
   108
  **PENNSYLVANIA
        POWER COMPANY**
 
 **MANAGEMENT’S
        DISCUSSION AND ANALYSIS OF**
 **RESULTS
        OF
        OPERATIONS AND FINANCIAL CONDITION**
 
 
 Penn is a wholly owned, electric utility subsidiary of OE. Penn conducts
        business in western Pennsylvania, providing regulated electric distribution
        services. Penn also provides generation services to those customers electing
        to
        retain Penn as their power supplier. Penn's rate restructuring plan and its
        associated transition charge revenue recovery was completed in 2005. Its
        power
        supply requirements are provided by FES - an affiliated company.
 
 **FirstEnergy
        Intra-System Generation Asset Transfers**
 
 On
        May 13, 2005,
        Penn, and on May 18, 2005, the Ohio Companies, entered into certain
        agreements implementing a series of intra-system generation asset transfers
        that
        were completed in the fourth quarter of 2005. The asset transfers resulted
        in
        the respective undivided ownership interests of the Ohio Companies and Penn
        in
        FirstEnergy’s nuclear and non-nuclear generation assets being owned by NGC and
        FGCO, respectively.
 
 On
        October 24, 2005,
        Penn completed the intra-system transfer of non-nuclear generation assets
        to
        FGCO. Prior to the transfer, FGCO, as lessee under a Master Facility Lease
        with
        the Ohio Companies and Penn, leased, operated and maintained the non-nuclear
        generation assets that it now owns. The asset transfers were consummated
        pursuant to FGCO's purchase option under the Master Facility Lease.
 
 On
        December 16,
        2005, Penn completed the intra-system transfer of its ownership interests
        in the
        nuclear generation assets to NGC through an asset spin-off in the form of
        a
        dividend. FENOC continues to operate and maintain the nuclear generation
        assets.
 
 These
        transactions
        were undertaken pursuant to the Ohio Companies’ and Penn’s restructuring plans
        that were approved by the PUCO and the PPUC, respectively, under applicable
        Ohio
        and Pennsylvania electric utility restructuring legislation. Consistent with
        the
        restructuring plans, generation assets that had been owned by the Ohio Companies
        and Penn were required to be separated from the regulated delivery business
        of
        those companies through transfer to a separate corporate entity. The
        transactions essentially completed the divestitures contemplated by the
        restructuring plans by transferring the ownership interests to NGC and FGCO
        without impacting the operation of the plants.
 
 The transfers will
        affect Penn’s
        near-term results with reductions in both revenues and expenses. Revenues
        are
        reduced due to the termination of certain arrangements with FES, under which
        Penn previously sold its nuclear-generated KWH to FES and leased its non-nuclear
        generation assets to FGCO, a subsidiary of FES. Penn’s expenses are lower due to
        the nuclear fuel and operating costs assumed by NGC as well as depreciation
        and
        property tax expenses assumed by FGCO and NGC related to the transferred
        generating assets. In addition, Penn receives interest income on associated
        company notes receivable from the transfer of its generation net assets.
        FES
        will continue to provide Penn’s PLR requirements under revised purchased power
        arrangements for the three-year period beginning January 1, 2006 (see
        Outlook -- Regulatory Matters).
  109
 
 The
        effects on
        Penn’s results of operations in the first quarter of 2006 compared to the first
        quarter of 2005 from the generation asset transfers are summarized in the
        following table:
  **Intra-System
                    Generation Asset Transfers****First
                    Quarter 2006 vs. First Quarter 2005 Income Statement
                    Effects*****Increase
                    (Decrease)***
                
                ***(In
                    millions)***Operating
                    Revenues:Non-nuclear
                    generating units rent
                
                $
                (5
                )
                (a)Nuclear
                    generated KWH sales
                
                
                (39
                )
                (b)Total
                    -
                    Operating Revenues Effect
                
                
                (44
                )Operating
                    Expenses and Taxes:Fuel
                    costs -
                    nuclear
                
                
                (6
                )
                (c)Nuclear
                    operating costs
                
                
                (20
                )
                (c)Provision
                    for
                    depreciation
                
                
                (2
                )
                (d)Income
                    taxes
                
                
                (7
                )
                (g)Total-
                    Operating Expenses and Taxes Effect
                
                
                (35
                )Operating
                    Income Effect
                
                
                (9
                )Other
                    Income:Interest
                    income from notes receivable
                
                
                2
                
                (e)Income
                    taxes
                
                
                1
                
                (g)Total-Other
                    Income Effect
                
                
                1Net
                    interest
                    Charges:Allowance
                    for
                    funds used during construction
                
                
                (1
                )
                (f)Total-Net
                    Interest Charges Effect
                
                
                1Net
                    Income
                    Effect
                
                $
                (9
                )(a)
                    Elimination of non-nuclear generation assets lease to
                    FGCO.(b)
                    Reduction
                    of nuclear generated wholesale KWH sales to FES.(c)
                    Reduction
                    of nuclear fuel and operating costs.(d)
                    Reduction
                    of depreciation expense and asset retirement obligation accretion
                    related
                    togeneration
                    assets.(e)
                    Interest
                    income on associated company notes receivable from the transfer
                    of
                    generation net assets.(f)
                    Reduction
                    of allowance for borrowed funds used during construction on nuclear
                    capitalexpenditures.(g)
                    Income tax
                    effect of the above adjustments.
 **Results
        of Operations**
 
 Earnings on common stock in the first quarter of 2006 decreased to $0.6 million
        from $14 million in the first quarter of 2005. The lower earnings resulted
        principally from the generation asset transfer effects shown in the table
        above.
 
 *Operating
        Revenues*
 
 Operating revenues decreased by $52 million, or 39%, in the first quarter
        of
        2006 as compared with the first quarter of 2005, primarily due to the generation
        asset transfer impact discussed in the table above. Excluding the effects
        of the
        asset transfer, operating revenues decreased by $8 million, or 9%. That decrease
        resulted from lower distribution revenues of $9 million primarily
        reflecting the completion of Penn's transition costs recovery, and lower
        wholesale revenues of $6 million resulting from the termination of a
        wholesale sales agreement with a non-affiliate in December 2005. The decrease
        in
        distribution KWH deliveries to residential and commercial customers reflected
        milder weather in the first quarter of 2006. The distribution and wholesale
        revenue decreases were partially offset by an increase in retail generation
        revenues of $6 million, primarily from higher composite unit prices associated
        with a 5% rate increase permitted by the PPUC for all customer classes -
        retail
        generation KWH sales remained substantially unchanged.
 
 Changes in distribution deliveries in the first quarter of 2006 from the
        same
        period of 2005 are summarized in the following table:
 
 **Changes
                  in Distribution Deliveries****Increase
                  (Decrease)**Residential
              
              
              (3
              )%Commercial
              
              
              (1
              )%Industrial
              
              
              4
              %**Total
                  Distribution Deliveries**
              
              
              -
              %
 
  110
 
 *Operating
        Expenses and Taxes*
 
 Total operating expenses and taxes decreased by $37 million in the first
        quarter
        of 2006 from the first quarter of 2005 principally due to the generation
        asset
        transfer impact as shown in the table above. Excluding the asset transfer
        effects, the following presents changes from the prior year by expense
        category:
 
 **Operating
                  Expenses and Taxes - Changes*****(In
                  millions)*****Increase
                  (Decrease)**Purchased
                  power costs
              
              $
              8Other
                  operating costs
              
              
              1Amortization
                  of regulatory assets
              
              
              (6
              )Income
                  taxes
              
              
              (5
              )**Total
                  operating expenses and taxes**
              
              $
              (2
              )
 
 I ncreased
        purchased
        power costs in the first quarter of 2006, compared with the first quarter
        of
        2005, resulted from higher unit prices associated with the new power supply
        agreement with FES, partially offset by a 13% decrease in KWH purchased due
        to
        lower generation sales requirements. Other operating costs increased due
        to
        transmission expenses associated with MISO Day 2 operations that began in
        April
        2005.
 
 Amortization of regulatory assets was lower in the first quarter of 2006
        as
        compared to the same period of 2005 due to the completion of Penn's rate
        restructuring plan and related transition cost amortization.
 
 *Other
        Income
        (Expense)*
 
 Other income increased $3 million in the first quarter of 2006, compared
        with
        the first quarter of 2005, in part due to the impact of the generation asset
        transfer. Excluding the effects of the asset transfer, other income was
        $2 million higher. This increase was primarily due to the absence in 2006
        of accruals for a $0.7 million civil penalty payable to the DOJ and
        $0.8 million settlement for environmental projects in connection with the
        Sammis New Source Review settlement in the first quarter of 2005 (see
        Environmental Matters).
 
 *Net
        Interest
        Charges*
 
 Excluding the effects of the asset transfer, net interest charges increased
        by
        $2 million in the first quarter of 2006, as compared to the first quarter
        of 2005. This increase was primarily due to a loss incurred on reacquired
        pollution control notes in the first quarter of 2006.
 
 **Capital
        Resources and Liquidity**
 
 Penn’s cash requirements in 2006 for operating expenses, construction
        expenditures and scheduled debt maturities are expected to be met with
        a combination
        of cash from operations and short-term credit arrangements. Available borrowing
        capacity under credit facilities will be used to manage working capital
        requirements.
 
 *Changes
        in Cash
        Position*
 
 Penn had $41,000 of cash and cash equivalents as of March 31, 2006 compared
        with $24,000 as of December 31, 2005. The major sources for changes in
        these balances are summarized below.
 
 *Cash
        Flows From
        Operating Activities*
 
 Net cash provided from operating activities in the first quarter of 2006,
        compared with the corresponding 2005 period, was as follows:
 
 **Three
                  Months Ended****March
                  31,****Operating
                  Cash Flows**
              
              **2006**
              
              **2005*****(In
                  millions)***Cash
                  earnings(1)
              
              $
              4
              
              $
              30Working
                  capital and other
              
              
              58
              
              
              8Net
                  cash
                  provided from operating activities
              
              $
              62
              
              $
              38
 
 (1)
            Cash
                earnings
                is a non-GAAP measure (see reconciliation
                below).  111
  Cash
        earnings (in
        the table above) are not a measure of performance calculated in accordance
        with
        GAAP. Penn believes that cash earnings are 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****March
                  31,****Reconciliation
                  of Cash Earnings**
              
              **2006**
              
              **2005*****(In
                  millions)***Net
                  Income
                  (GAAP)
              
              $
              1
              
              $
              15Non-Cash
                  Charges (Credits):Provision
                  for
                  depreciation
              
              
              2
              
              
              3Amortization
                  of regulatory assets
              
              
              3
              
              
              10Nuclear
                  fuel
                  and other amortization
              
              
              -
              
              
              4Deferred
                  income taxes and investment tax credits, net
              
              
              (2
              )
              
              (2
              )Other
                  non-cash
                  expenses
              
              
              -
              
              
              -Cash
                  earnings
                  (Non-GAAP)
              
              $
              4
              
              $
              30
  The
        $26 million decrease in cash earnings is described above under “Results of
        Operations.” The $50 million change in working capital was primarily due to
        increases in cash provided from the settlement of receivables of
        $30 million and a $78 million change in prepayments and other current
        assets, principally as a result of the asset transfer discussed above, partially
        offset by increased cash outflows from the settlement of accounts payable
        of
        $50 million and a $7 million change in accrued taxes.
 
 *Cash
        Flows From
        Financing Activities*
 
 Net cash used for financing activities totaled $48 million in the first quarter
        of 2006, compared with $10 million in the first quarter of 2005. This
        increase resulted from $54 million of long-term debt redemptions in 2006
        principally as a result of the generation asset transfer discussed above,
        partially offset by a net $8 million increase in short-term borrowings and
        the
        absence of $8 million in common stock dividend payments to OE in the first
        quarter of 2005.
 
 Penn had $11 million of cash and temporary investments (which included
        short-term notes receivable from associated companies) and $19 million of
        short-term indebtedness as of March 31, 2006. Penn has authorization from
        the SEC, continued by FERC rules adopted as a result of EPACT's repeal of
        PUHCA,
 to incur short-term debt up to its charter limit of $50 million
        (including the utility money pool). Penn had the capability to issue
        $64 million of additional FMB on the basis of property additions and
        retired bonds as of March 31, 2006. Based upon applicable earnings coverage
        tests, Penn could issue up to $415 million of preferred stock (assuming no
        additional debt was issued) as of March 31, 2006.
 
 Penn Power Funding LLC (Penn Funding), a wholly owned subsidiary of Penn,
        is a
        limited liability company whose borrowings are secured by customer accounts
        receivable purchased from Penn. Penn Funding can borrow up to the full amount
        of
        $25 million available as of March 31, 2006 under a receivables
        financing arrangement which expires June 29, 2006. 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 March 31,
        2006, the facility was drawn for $19 million.
 
 Penn has the ability to borrow under a syndicated $2 billion five-year revolving
        credit facility, which expires in June 2010, along with FirstEnergy, OE,
        CEI,
        TE, JCP&L, Met-Ed, Penelec, FES, and ATSI. Borrowings under the facility are
        available to each Borrower separately and will mature on the earlier of 364
        days
        from the date of borrowing or the commitment termination date. Penn's borrowing
        limit under the facility is $50 million.
 
 Under the revolving credit facility, borrowers may request the issuance of
        letters of credit expiring up to one year from the date of issuance. The
        stated
        amount of outstanding letters of credit will count against total commitments
        available under the facility and against the applicable borrower’s borrowing
        sub-limit. Total unused borrowing capability under the existing credit facility
        and accounts receivable financing facilities totaled $56 million as of
        March 31, 2006.
 
 The revolving credit facility contains financial covenants requiring each
        borrower to maintain a consolidated debt to total capitalization ratio of
        no
        more than 65%. As of March 31, 2006, Penn's debt to total capitalization as
        defined under the revolving credit facility was 35%.
 
 The facility does not contain any provisions that either restrict Penn's
        ability
        to borrow or accelerate repayment of outstanding advances as a result of
        any
        change in its credit ratings. Pricing is defined in “pricing grids”, whereby the
        cost of funds borrowed under the facility is related to Penn's credit
        ratings.
  112
 
 Penn has the ability to borrow from its regulated affiliates and FirstEnergy
        to
        meet its short-term working capital requirements. FESC administers this money
        pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries.
        Companies receiving a loan under the money pool agreements must repay the
        principal amount, together with accrued interest, within 364 days of borrowing
        the funds. The rate of interest is the same for each company receiving a
        loan
        from the pool and is based on the average cost of funds available through
        the
        pool. The average interest rate for borrowings under these arrangements in
        the
        first quarter of 2006 was 4.58%.
 
 Penn's access to the capital markets and the costs of financing are influenced
        by the ratings of its securities and the securities of OE and FirstEnergy.
        The
        rating outlook from S&P on all securities is stable. Moody's and Fitch's
        ratings outlook on all securities is positive.
 
 In
        April 2006,
        pollution control notes that were formerly obligations of Penn were refinanced
        and became obligations of FGCO and NGC. The proceeds from the refinancings
        were
        used to repay a portion of their associated company notes payable to Penn.
        With
        those repayments, Penn redeemed pollution control notes in the principal
        amount
        of $6.95 million at 5.45%.
 
 *Cash
        Flows From
        Investing Activities*
 
 Net cash used for investing activities totaled $14 million in the first quarter
        of 2006, compared with $28 million in the same quarter of 2005. The
        $14 million decrease in the 2006 period reflects a $23 million reduction in
        property additions, principally as a result of the generation asset transfer
        discussed above, partially offset by a $9 million increase in loans to
        associated companies.
 
 During the remaining three quarters of 2006, capital requirements for property
        additions are expected to be about $14 million. Penn has sinking fund
        requirements of approximately $1 million for maturing long-term debt during
        the remainder of 2006. These cash requirements are expected to be satisfied
        from
        internal cash and short-term credit arrangements.
 
 Penn’s capital spending for the period 2006-2010 is expected to be about $91
        million of which approximately $19 million applies to 2006. Penn had no
        other material obligations as of March 31, 2006 that have not been
        recognized on its Consolidated Balance Sheet.
 
 **OUTLOOK**
  The
        electric
        industry continues to transition to a more competitive environment and all
        of
        Penn’s customers can select alternative energy suppliers. Penn continues to
        deliver power to residential homes and businesses through its existing
        distribution system, which remains regulated. Customer rates have been
        restructured into separate components to support customer choice. Penn has
        a
        continuing responsibility to provide power to those customers not choosing
        to
        receive power from an alternative energy supplier subject to certain
        limits.
 
 **Regulatory
        Matters**
  Regulatory
        assets
        and liabilities are costs which have been authorized by the PPUC and the
        FERC
        for recovery from or credit to customers in future periods and, without such
        authorization, would have been charged or credited to income when incurred.
        Penn’s net regulatory liabilities were approximately $64 million and
        $59 million as of March 31, 2006 and December 31, 2005,
        respectively, and are included under Noncurrent Liabilities on the Consolidated
        Balance Sheets.
 
 On
        October 11,
        2005, Penn filed a plan with the PPUC to secure electricity supply for its
        customers at set rates following the end of its transition period on
        December 31, 2006. Penn recommended that an RFP process cover the period
        January 1, 2007 through May 31, 2008. Hearings were held on
        January 10, 2006 with main briefs filed on January 27, 2006 and reply
        briefs filed on February 3, 2006. On February 16, 2006, the ALJ issued
        a Recommended Decision to adopt Penn's RFP process with modifications. The
        PPUC
        approved the Recommended Decision with additional modifications on April
        20,
        2006. The approved plan is designed to provide customers with PLR service
        for
        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.
 
 On
        November 1, 2005,
        FES filed a power sales agreement for FERC approval that would permit Penn
        to
        obtain its PLR power requirements from FES at a fixed price equal to the
        retail
        generation price during 2006. On December 29, 2005, the FERC issued an
        order setting the power sales agreement for hearing. The order required FES
        to
        submit additional evidence in support of the reasonableness of the prices
        charged in Penn’s contract. A pre-hearing conference was held on
        January 18, 2006 to determine the hearing schedule in this case. FES
        expects an initial decision to be issued in this case in late January 2007,
        as a
        result of an April 20, 2006 extension of the procedural schedule. The outcome
        of
        this proceeding cannot be predicted. FES has sought rehearing of the
        December 29, 2005 order and the FERC granted rehearing for further
        consideration on March 1, 2006.
  113
  See Note 11 to the consolidated financial statements for further details
        and a complete discussion of regulatory matters in Pennsylvania.
 
 **Environmental
        Matters**
 
 Penn
        accrues
        environmental liabilities when it concludes that it is probable that it has
        an
        obligation for such costs and can reasonably estimate the amount of such
        costs.
        Unasserted claims are reflected in Penn’s determination of environmental
        liabilities and are accrued in the period that they are both probable and
        reasonably estimable.
 
 *W.
        H. Sammis
        Plant*
 
 In
        1999 and 2000,
        the EPA issued NOV or Compliance Orders to nine utilities alleging violations
        of
        the Clean Air Act based on operation and maintenance of 44 power plants,
        including the W. H. Sammis Plant, which was owned at that time by OE and
        Penn.
        In addition, the DOJ filed eight civil complaints against various investor-owned
        utilities, including a complaint against OE and Penn in the U.S. District
        Court
        for the Southern District of Ohio. These cases are referred to as New Source
        Review cases. On March 18, 2005, OE and Penn announced that they had
        reached a settlement with the EPA, the DOJ and three states (Connecticut,
        New
        Jersey, and New York) that resolved all issues related to the W. H. Sammis
        Plant
        New Source Review litigation. This
        settlement
        agreement was approved by the Court on July 11, 2005, and requires
        reductions of NO x and SO 2 emissions at the
        W. H. Sammis Plant and other coal fired plants through the installation of
        pollution control devices and provides for stipulated penalties for failure
        to
        install and operate such pollution controls in accordance with that
        agreement. Consequently, if OE
        and Penn fail to install such pollution control devices, for any reason,
        including, but not limited to, the failure of any third-party contractor
        to
        timely meet its delivery obligations for such devices, OE and Penn could
        be
        exposed to penalties under the settlement agreement. 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). On 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.
 
 **Other
        Legal Proceedings**
 
 There
        are various
        lawsuits, claims (including claims for asbestos exposure) and proceedings
        related to Penn’s normal business operations pending against Penn. The other
        material items not otherwise discussed above are described below.
 
 *Power
        Outages
        and Related Litigation-*
 
 On
        August 14,
        2003, various states and parts of southern Canada experienced widespread
        power
        outages. The outages affected approximately 1.4 million customers in
        FirstEnergy’s service area. The U.S. - Canada Power System Outage Task Force’s
        final report in April 2004 on the outages 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 March 31, 2006 for any
        expenditure in excess of those actually incurred through that date. 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.
   114
  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 and results of operations.
 
 See
        Note 10(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 adopted 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. This
        EITF issue will
        not have a material impact on Penn's financial results.
 
 *SFAS
        155 -
“Accounting for Certain Hybrid Financial Instruments-an amendment of FASB
        Statements No. 133 and 140”*
  In
        February 2006, the FASB issued SFAS 155 which amends SFAS 133 “Accounting for
        Derivative Instruments and Hedging Activities,” (SFAS 133) and SFAS 140
“Accounting for Transfers and Servicing of Financial Assets and Extinguishments
        of Liabilities.” This Statement permits fair value remeasurement for any hybrid
        financial instrument that contains an embedded derivative that otherwise
        would
        require bifurcation, clarifies which interest-only strips and principal-only
        strips are not subject to the requirements of SFAS 133, establishes a
        requirement to evaluate interests in securitized financial assets to identify
        interests that are freestanding derivatives or that are hybrid financial
        instruments that contain an embedded derivative requiring bifurcation, clarifies
        that concentrations of credit risk in the form of subordination are not embedded
        derivatives and amends SFAS 140 to eliminate the prohibition on a qualifying
        special-purpose entity from holding a derivative financial instrument that
        pertains to a beneficial interest other than another derivative instrument.
        This
        Statement is effective for all financial instruments acquired or issued
        beginning January 1, 2007. Penn is currently evaluating the impact of this
        Statement on its financial statements.
   115
  **JERSEY
                      CENTRAL POWER & LIGHT
                      COMPANY****CONSOLIDATED
                      STATEMENTS OF INCOME AND COMPREHENSIVE
                      INCOME****(Unaudited)****Three
                      Months Ended****March
                      31,****2006**
                  
                  **2005****Restated****STATEMENTS
                      OF INCOME**
                  
                  ***(In
                      thousands)*****OPERATING
                      REVENUES**
                  
                  $
                  575,792
                  
                  $
                  529,092**OPERATING
                      EXPENSES AND TAXES:**Purchased
                      power
                  
                  
                  315,710
                  
                  
                  277,132Other
                      operating costs
                  
                  
                  83,028
                  
                  
                  101,067Provision
                      for
                      depreciation
                  
                  
                  20,628
                  
                  
                  20,206Amortization
                      of regulatory assets
                  
                  
                  66,745
                  
                  
                  68,374General
                      taxes
                  
                  
                  16,232
                  
                  
                  15,440Income
                      taxes
                  
                  
                  22,359
                  
                  
                  12,968Total
                      operating expenses and taxes
                  
                  
                  524,702
                  
                  
                  495,187**OPERATING
                      INCOME**
                  
                  
                  51,090
                  
                  
                  33,905**OTHER
                      INCOME (net of income taxes)**
                  
                  
                  2,344
                  
                  
                  44**NET
                      INTEREST CHARGES:**Interest
                      on
                      long-term debt
                  
                  
                  18,059
                  
                  
                  19,405Allowance
                      for
                      borrowed funds used during construction
                  
                  
                  (892
                  )
                  
                  (403
                  )Deferred
                      interest
                  
                  
                  (1,400
                  )
                  
                  (911
                  )Other
                      interest
                      expense
                  
                  
                  3,957
                  
                  
                  2,409Net
                      interest
                      charges
                  
                  
                  19,724
                  
                  
                  20,500**NET
                      INCOME**
                  
                  
                  33,710
                  
                  
                  13,449**PREFERRED
                      STOCK DIVIDEND REQUIREMENTS**
                  
                  
                  125
                  
                  
                  125**EARNINGS
                      ON COMMON STOCK**
                  
                  $
                  33,585
                  
                  $
                  13,324**STATEMENTS
                      OF COMPREHENSIVE INCOME****NET
                      INCOME**
                  
                  $
                  33,710
                  
                  $
                  13,449**OTHER
                      COMPREHENSIVE INCOME:**Unrealized
                      gain on derivative hedges
                  
                  
                  69
                  
                  
                  69Income
                      tax
                      expense related to other comprehensive income
                  
                  
                  28
                  
                  
                  28Other
                      comprehensive income, net of tax
                  
                  
                  41
                  
                  
                  41**TOTAL
                      COMPREHENSIVE INCOME**
                  
                  $
                  33,751
                  
                  $
                  13,490The
                      preceding
                      Notes to Consolidated Financial Statements as they relate to
                      Jersey
                      Central Power & Light Companyare
                      an
                      integral part of these statements.
   116
  **JERSEY
                      CENTRAL POWER & LIGHT
                      COMPANY****CONSOLIDATED
                      BALANCE SHEETS****(Unaudited)****March
                      31,**
                  
                  **December
                      31,****2006**
                  
                  **2005*****(In
                      thousands)*****ASSETS****UTILITY
                      PLANT:**In
                      service
                  
                  $
                  3,935,904
                  
                  $
                  3,902,684Less
                      -
                      Accumulated provision for depreciation
                  
                  
                  1,453,740
                  
                  
                  1,445,7182,482,164
                  
                  
                  2,456,966Construction
                      work in progress
                  
                  
                  99,320
                  
                  
                  98,7202,581,484
                  
                  
                  2,555,686**OTHER
                      PROPERTY AND INVESTMENTS:**Nuclear
                      plant
                      decommissioning trusts
                  
                  
                  149,398
                  
                  
                  145,975Nuclear
                      fuel
                      disposal trust
                  
                  
                  165,198
                  
                  
                  164,203Other
                  
                  
                  13,443
                  
                  
                  16,693328,039
                  
                  
                  326,871**CURRENT
                      ASSETS:**Cash
                      and cash
                      equivalents
                  
                  
                  103
                  
                  
                  102Notes
                      receivable - associated companies
                  
                  
                  21,551
                  
                  
                  18,419Receivables-Customers
                      (less accumulated provisions of $3,225,000 and $3,830,000,respectively,
                      for uncollectible accounts)
                  
                  
                  218,926
                  
                  
                  258,077Associated
                      companies
                  
                  
                  2,342
                  
                  
                  203Other
                      (less
                      accumulated provisions of $227,000 and $204,000,respectively,
                      for uncollectible accounts)
                  
                  
                  30,463
                  
                  
                  41,456Materials
                      and
                      supplies, at average cost
                  
                  
                  1,849
                  
                  
                  2,104Prepayments
                      and other
                  
                  
                  9,002
                  
                  
                  17,065284,236
                  
                  
                  337,426**DEFERRED
                      CHARGES AND OTHER ASSETS:**Regulatory
                      assets
                  
                  
                  2,167,886
                  
                  
                  2,226,591Goodwill
                  
                  
                  1,978,350
                  
                  
                  1,985,858Prepaid
                      pension costs
                  
                  
                  149,407
                  
                  
                  148,054Other
                  
                  
                  4,403
                  
                  
                  3,6204,300,046
                  
                  
                  4,364,123$
                  7,493,805
                  
                  $
                  7,584,106**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
                  
                  
                  2,995,715
                  
                  
                  3,003,190Accumulated
                      other comprehensive loss
                  
                  
                  (1,989
                  )
                  
                  (2,030
                  )Retained
                      earnings
                  
                  
                  64,475
                  
                  
                  55,890Total
                      common
                      stockholder's equity
                  
                  
                  3,211,914
                  
                  
                  3,210,763Preferred
                      stock
                  
                  
                  12,649
                  
                  
                  12,649Long-term
                      debt
                      and other long-term obligations
                  
                  
                  967,812
                  
                  
                  972,0614,192,375
                  
                  
                  4,195,473**CURRENT
                      LIABILITIES:**Currently
                      payable long-term debt
                  
                  
                  207,408
                  
                  
                  207,231Notes
                      payable-Associated
                      companies
                  
                  
                  278,158
                  
                  
                  181,346Accounts
                      payable-Associated
                      companies
                  
                  
                  5,793
                  
                  
                  37,955Other
                  
                  
                  112,670
                  
                  
                  149,501Accrued
                      taxes
                  
                  
                  86,462
                  
                  
                  54,356Accrued
                      interest
                  
                  
                  33,685
                  
                  
                  19,916Cash
                      collateral from suppliers
                  
                  
                  32,568
                  
                  
                  141,225Other
                  
                  
                  83,725
                  
                  
                  86,884840,469
                  
                  
                  878,414**NONCURRENT
                      LIABILITIES:**Power
                      purchase
                      contract loss liability
                  
                  
                  1,183,501
                  
                  
                  1,237,249Accumulated
                      deferred income taxes
                  
                  
                  814,797
                  
                  
                  812,034Nuclear
                      fuel
                      disposal costs
                  
                  
                  176,981
                  
                  
                  175,156Asset
                      retirement obligation
                  
                  
                  80,729
                  
                  
                  79,527Retirement
                      benefits
                  
                  
                  72,905
                  
                  
                  72,454Other
                  
                  
                  132,048
                  
                  
                  133,7992,460,961
                  
                  
                  2,510,219**COMMITMENTS
                      AND CONTINGENCIES (Note 10)**$
                  7,493,805
                  
                  $
                  7,584,106The
                      preceding
                      Notes to Consolidated Financial Statements as they relate to
                      Jersey
                      Central Power & Light Company are an integral partof
                      these
                      balance sheets.
   117
  **JERSEY
                      CENTRAL POWER & LIGHT
                      COMPANY****CONSOLIDATED
                      STATEMENTS OF CASH
                      FLOWS****(Unaudited)****Three
                      Months Ended****March
                      31,****2006**
                  
                  **2005****Restated*****(In
                      thousands)*****CASH
                      FLOWS FROM OPERATING ACTIVITIES:**Net
                      income
                  
                  $
                  33,710
                  
                  $
                  13,449Adjustments
                      to
                      reconcile net income to net cash from operating
                      activities-Provision
                      for
                      depreciation
                  
                  
                  20,628
                  
                  
                  20,206Amortization
                      of regulatory assets
                  
                  
                  66,745
                  
                  
                  68,374Deferred
                      purchased power and other costs
                  
                  
                  (61,868
                  )
                  
                  (73,359
                  )Deferred
                      income taxes and investment tax credits, net
                  
                  
                  3,826
                  
                  
                  7,169Accrued
                      retirement benefit obligation
                  
                  
                  (902
                  )
                  
                  (4,728
                  )Accrued
                      compensation, net
                  
                  
                  (1,834
                  )
                  
                  5,413Cash
                      collateral from (returned to) suppliers
                  
                  
                  (108,657
                  )
                  
                  6,365Decrease
                      (increase) in operating assets:Receivables
                  
                  
                  48,005
                  
                  
                  14,849Materials
                      and
                      supplies
                  
                  
                  255
                  
                  
                  82Prepayments
                      and other current assets
                  
                  
                  8,063
                  
                  
                  9,250Increase
                      (decrease) in operating liabilities:Accounts
                      payable
                  
                  
                  (68,993
                  )
                  
                  (30,390
                  )Accrued
                      taxes
                  
                  
                  32,106
                  
                  
                  39,363Accrued
                      interest
                  
                  
                  13,769
                  
                  
                  15,303Other
                  
                  
                  (5,773
                  )
                  
                  5,956Net
                      cash
                      provided from (used for) operating activities
                  
                  
                  (20,920
                  )
                  
                  97,302**CASH
                      FLOWS FROM FINANCING ACTIVITIES:**New
                      Financing-Short-term
                      borrowings, net
                  
                  
                  96,812
                  
                  
                  -Redemptions
                      and Repayments-Long-term
                      debt
                  
                  
                  (3,731
                  )
                  
                  (3,883
                  )Short-term
                      borrowings, net
                  
                  
                  -
                  
                  
                  (43,738
                  )Dividend
                      Payments-Common
                      stock
                  
                  
                  (25,000
                  )
                  
                  (20,000
                  )Preferred
                      stock
                  
                  
                  (125
                  )
                  
                  (125
                  )Net
                      cash
                      provided from (used for) financing activities
                  
                  
                  67,956
                  
                  
                  (67,746
                  )**CASH
                      FLOWS FROM INVESTING ACTIVITIES:**Property
                      additions
                  
                  
                  (45,361
                  )
                  
                  (28,124
                  )Loans
                      to
                      associated companies, net
                  
                  
                  (3,132
                  )
                  
                  (898
                  )Proceeds
                      from
                      nuclear decommissioning trust fund sales
                  
                  
                  45,865
                  
                  
                  28,351Investments
                      in
                      nuclear decommissioning trust funds
                  
                  
                  (46,588
                  )
                  
                  (29,075
                  )Other
                  
                  
                  2,181
                  
                  
                  69Net
                      cash used
                      for investing activities
                  
                  
                  (47,035
                  )
                  
                  (29,677
                  )Net
                      increase
                      (decrease) in cash and cash equivalents
                  
                  
                  1
                  
                  
                  (121
                  )Cash
                      and cash
                      equivalents at beginning of period
                  
                  
                  102
                  
                  
                  162Cash
                      and cash
                      equivalents at end of period
                  
                  $
                  103
                  
                  $
                  41The
                      preceding
                      Notes to Consolidated Financial Statements as they relate to
                      Jersey
                      Central Power & Light Company are anintegral
                      part
                      of these statements.
 
  118
  ***Report
        of Independent Registered Public Accounting Firm***
 
 
 
 
 
 
 
 
 
 To
        the Stockholder
        and Board of
 Directors
        of Jersey
        Central
 Power
&
Light
        Company:
 
 We
        have reviewed the
        accompanying consolidated balance sheet of Jersey Central Power & Light
        Company and its subsidiaries as of March 31, 2006, and the related
        consolidated statements of income, comprehensive income and cash flows for
        each
        of the three-month periods ended March 31, 2006 and 2005. These interim
        financial statements are the responsibility of the Company’s
        management.
 
 We
        conducted our
        review in accordance with the standards of the Public Company Accounting
        Oversight Board (United States). A review of interim financial information
        consists principally of applying analytical procedures and making inquiries
        of
        persons responsible for financial and accounting matters. It is substantially
        less in scope than an audit conducted in accordance with the standards of
        the
        Public Company Accounting Oversight Board, the objective of which is the
        expression of an opinion regarding the financial statements taken as a whole.
        Accordingly, we do not express such an opinion.
 
 Based
        on our review,
        we are not aware of any material modifications that should be made to the
        accompanying consolidated interim financial statements for them to be in
        conformity with accounting principles generally accepted in the United States
        of
        America.
 
 We
        previously
        audited, in accordance with the standards of the Public Company Accounting
        Oversight Board (United States), the consolidated balance sheet as of December
        31, 2005, and the related consolidated statements of income, capitalization,
        common stockholder’s equity, preferred stock, cash flows and taxes for the year
        then ended (not presented herein), and in our report (which contained references
        to the Company’s restatement of its previously issued consolidated financial
        statements for the years ended December 31, 2004 and 2003 as discussed in
        Note
        2(I) to those consolidated financial statements) dated February 27, 2006,
        we
        expressed an unqualified opinion on those consolidated financial statements.
        In
        our opinion, the information set forth in the accompanying consolidated balance
        sheet as of December 31, 2005, is fairly stated in all material respects in
        relation to the consolidated balance sheet from which it has been
        derived.
 
 
 
 
 PricewaterhouseCoopers
        LLP
 Cleveland,
        Ohio
 May
        8,
        2006
 
 
  119
  **JERSEY
        CENTRAL POWER & LIGHT COMPANY**
 
 **MANAGEMENT’S
        DISCUSSION AND** **ANALYSIS
        OF**
 **RESULTS
        OF
        OPERATIONS** **** **AND
        FINANCIAL CONDITION**
 
 
 JCP&L is a wholly owned, electric utility subsidiary of FirstEnergy.
        JCP&L conducts business in New Jersey, providing regulated electric
        transmission and distribution services. JCP&L also provides generation
        services to those customers electing to retain JCP&L as their power
        supplier.
 
 **Restatements**
  As
        further discussed
        in Note 15 to the Consolidated Financial Statements, JCP&L restated its
        consolidated financial statements for the three months ended March 31, 2005.
        The
        revisions are the result of a tax audit from the State of New Jersey, in
        which
        JCP&L became aware that the New Jersey Transitional Energy Facilities
        Assessment is not an allowable deduction for state income tax
        purposes .
 
 **Results
        of Operations**
 
 Earnings on common stock in the first quarter of 2006 increased to $33.6
        million
        from $13.3 million in 2005, principally due to higher operating revenues
        and lower other operating costs, partially offset by increases in purchased
        power costs and income taxes.
 
 *Operating
        Revenues*
 
 Operating revenues increased $46.7 million or 8.8% in the first quarter of
        2006
        compared with the same period of 2005 due to higher retail electric generation,
        distribution and wholesale revenues.
 
 Retail generation revenues increased by $37.8 million in the first quarter
        of
        2006 as compared to the previous year in all customer classes (residential - $14.9 million,
        commercial - $21.0 million and industrial - $1.7 million). The
        increases were due to higher unit prices resulting from the BGS auction
        effective in May 2005 and increases in sales volume (commercial - 6.8% and
        industrial - 3.3%). The sales volume increases were primarily due to lower
        customer shopping. Generation provided by alternative suppliers as a percent
        of
        total sales delivered in JCP&L’s service area decreased by 6.0 and 2.7
        percentage points for commercial and industrial customers, respectively.
        Residential KWH generation sales declined by 4.2% from the previous year,
        reflecting unseasonably mild weather in the first quarter of 2006 (heating
        degree days were 16.5% lower than in the first quarter of 2005). Wholesale
        sales
        revenues increased $1.8 million primarily due to higher market prices --
        wholesale KWH sales were virtually unchanged from the first quarter of 2005.
 
 The increase in distribution revenues of $5.3 million in the first quarter
        of
        2006 compared to the same period of 2005 was primarily due to higher composite
        unit prices resulting from a distribution rate increase pursuant to the
        stipulated settlements approved by the NJBPU on May 25, 2005. The effect of
        the increased prices was partially offset by lower distribution KWH
        sales.
 
 Changes in KWH sales by customer class in the first quarter of 2006 compared
        to
        the same period of 2005 are summarized in the following table:
 
 **Changes
                  in KWH Sales****Increase
                  (Decrease)**Electric
                  Generation:Retail
              
              
              0.5
              %Wholesale
              
              
              0.1
              %**Total
                  Electric Generation Sales**
              
              
              0.4
              %Distribution
                  Deliveries:Residential
              
              
              (4.2
              )%Commercial
              
              
              (1.1
              )%Industrial
              
              
              (7.1
              )%**Total
                  Distribution Deliveries**
              
              
              (3.3
              )%
  120
  The higher operating revenues also reflected an additional $1.0 million received
        in the first quarter of 2006 as compared to the first quarter of 2005 under
        a
        contract provision associated with the prior sale of TMI Unit 1. Under the
        contract, additional payments are received if subsequent energy prices rise
        above specified levels, which occurred. This payment is credited to JCP&L’s
        customers, resulting in no net earnings impact.
 
 *Operating
        Expenses and Taxes*
  Total operating expenses and taxes increased by $29.5 million in the first
        quarter of 2006 compared to the first quarter of 2005. The following table
        presents changes from the prior year by expense category:
 
 **Operating
                  Expenses and Taxes - Changes*****(In
                  millions)*****Increase
                  (Decrease)**Purchased
                  power costs
              
              $
              38.5Other
                  operating costs
              
              
              (18.0
              )Provision
                  for
                  depreciation
              
              
              0.4Amortization
                  of regulatory assets
              
              
              (1.6
              )General
                  taxes
              
              
              0.8Income
                  taxes
              
              
              9.4**Total
                  operating expenses and taxes**
              
              $
              29.5
 
 Purchased power costs increased $38.5 million in the first quarter of 2006
        compared to the same period of 2005. The increase reflected higher prices
        from
        the 2005 BGS auction and a 0.4% increase in total electric generation sales.
        The
        decrease of $18.0 million in other operating costs in the first quarter of
        2006 reflected in part the effects of a JCP&L labor strike in 2005. The
        JCP&L labor strike, which affected approximately 1,300 employees, began
        on December 8, 2004 and lasted until March 15, 2005. As a result of
        settling the strike later in 2005, associated company billings for work done
        on
        behalf of JCP&L of $15.4 million was absent in the first quarter of 2006. In
        addition, professional and contractor services declined by $2.5 million due
        to additional expenditures incurred in 2005 as a result of the strike. Income
        tax expense increased $9.4 million in the first quarter of 2006 as compared
        to the first quarter of 2005 due to higher pre-tax income.
 
 **Capital
        Resources and Liquidity**
  JCP&L’s cash requirements in 2006 for operating expenses, construction
        expenditures and scheduled debt maturities are expected to be met with a
        combination of cash from operations and funds from the capital markets.
 
 *Changes
        in Cash
        Position*
 
 As of March 31, 2006, JCP&L had $103,000 of cash and cash equivalents
        compared with $102,000 as of December 31, 2005. The major sources for
        changes in these balances are summarized below.
 
 *Cash
        Flows From
        Operating Activities*
 
 Cash provided from operating activities in the first quarter of 2006 compared
        with the first quarter of 2005 were as follows:
 
 **Three
                  Months Ended March 31,****Operating
                  Cash Flows**
              
              **2006**
              
              **2005*****(In
                  millions)***Cash
                  earnings(1)
              
              $
              60
              
              $
              37Working
                  capital and other
              
              
              (81
              )
              
              60Net
                  Cash
                  provided from (used for) Operating Activities
              
              $
              (21
              )
              $
              97
 
 (1 ) Cash
        earnings are a non-GAAP measure (see reconciliation
        below).
  121
 
 Cash earnings (in the table above) are not a measure of performance calculated
        in accordance with GAAP. JCP&L believes that cash earnings are 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****March
                  31****Reconciliation
                  of Cash Earnings**
              
              **2006**
              
              **2005*****(In
                  millions)***Net
                  Income
                  (GAAP)
              
              $
              34
              
              $
              13Non-Cash
                  Charges (Credits):Provision
                  for
                  depreciation
              
              
              21
              
              
              20Amortization
                  of regulatory assets
              
              
              67
              
              
              68Deferred
                  costs
                  recoverable as regulatory assets
              
              
              (62
              )
              
              (73
              )Deferred
                  income taxes
              
              
              4
              
              
              7Other
                  non-cash
                  expenses
              
              
              (4
              )
              
              2Cash
                  earnings
                  (Non-GAAP)
              
              $
              60
              
              $
              37
  The $23 million increase in cash earnings is described above and under
“Results of Operations.” The $141 million decrease from working capital
        primarily resulted from a $115 million change in cash collateral from suppliers
        and changes in accounts payable of approximately $39 million. In 2005,
        JCP&L received cash collateral payments from its suppliers and in the first
        quarter of 2006 returned $109 million back to its suppliers.
 
 *Cash
        Flows From
        Financing Activities*
 
 Net cash provided from financing activities was $68 million in the first
        quarter
        of 2006 as compared to net cash used of $68 million in same period of 2005.
        The increase resulted from a $97 million increase in new short-term borrowings
        and a $44 million reduction in debt redemptions in the first quarter of
        2006, partially offset by an additional $5 million of common stock dividend
        payments to FirstEnergy.
  JCP&L  had
        about $22
        million of cash and temporary investments (which includes short-term notes
        receivable from associated companies) and approximately $278 million of
        short-term indebtedness as of March 31, 2006. JCP&L has authorization
        from the SEC, continued by FERC rules adopted as a result of EPACT's repeal
        of
        PUHCA, to incur short-term debt up to its charter limit of $412 million
        (including the utility money pool). JCP&L will not issue FMB other than as
        collateral for senior notes, since its senior note indenture prohibits (subject
        to certain exceptions) JCP&L from issuing any debt which is senior to the
        senior notes. As of March 31, 2006, JCP&L had the capability to issue
        $625 million of additional senior notes based upon FMB collateral. As of
        March 31, 2006, based upon applicable earnings coverage tests and its
        charter, JCP&L could issue $1.5 billion of preferred stock (assuming no
        additional debt was issued).
 
 JCP&L has the ability to borrow from FirstEnergy and its regulated
        affiliates to meet its short-term working capital requirements. FESC administers
        this money pool and tracks surplus funds of FirstEnergy and its regulated
        subsidiaries. Companies receiving a loan under the money pool agreement must
        repay the principal, together with accrued interest, within 364 days of
        borrowing the funds. The rate of interest is the same for each company receiving
        a loan from the pool and is based on the average cost of funds available
        through
        the pool. The average interest rate for borrowings in the first quarter of
        2006
        was 4.58%.
 
 JCP&L, FirstEnergy, OE, Penn, CEI, TE, Penelec, Met-Ed, FES and ATSI, as
        Borrowers, have entered into a syndicated $2 billion five-year revolving
        credit facility which expires in June 2010. 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.
 
 Under the revolving credit facility, borrowers may request the issuance of
        letters of credit expiring up to one year from the date of issuance. The
        stated
        amount of outstanding letters of credit will count against total commitments
        available under the facility and against the applicable borrower’s borrowing
        sub-limit.
 
 The revolving credit facility contains financial covenants requiring each
        borrower to maintain a consolidated debt to total capitalization ratio of
        no
        more than 65%. As of March 31, 2006, JCP&L's debt to total
        capitalization as defined under the revolving credit facility was 27%.
 
 The facility does not contain any provisions that either restrict JCP&L's
        ability to borrow or accelerate repayment of outstanding advances as a result
        of
        any change in its credit ratings. Pricing is defined in “pricing grids”, whereby
        the cost of funds borrowed under the facility is related to its credit
        ratings.
  122
 
 JCP&L's access to the capital markets and the costs of financing are
        dependent on the ratings of its securities and that of FirstEnergy. As of
        March 31, 2006, JCP&L's and FirstEnergy’s ratings outlook from S&P
        on all securities was stable. The ratings outlook from Moody’s and Fitch on all
        securities is positive.
 
 *Cash
        Flows From
        Investing Activities*
 
 Net cash used in investing activities was $47 million in the first quarter
        of
        2006 compared to $30 million in the previous year. The $17 million
        change primarily resulted from a $17 million increase in property additions
        for distribution system reliability initiatives.
 
 During the last three quarters of 2006, capital requirements for property
        additions and improvements are expected to be about $132.5 million. These
        cash requirements are expected to be satisfied from a combination of internal
        cash, funds raised in the long-term debt capital markets and short-term credit
        arrangements.
 
 JCP&L’s capital spending for the period 2006-2010 is expected to be about
        $926 million for property additions, of which approximately $176 million
        applies to 2006.
 
 **Market
        Risk Information**
 
 JCP&L uses various market risk sensitive instruments, including derivative
        contracts, primarily to manage the risk of price fluctuations. Its Risk Policy
        Committee, comprised of members of senior management, provides general
        management oversight to risk management activities throughout JCP&L. They
        are responsible for promoting the effective design and implementation of
        sound
        risk management programs. They also oversee compliance with corporate risk
        management policies and established risk management practices.
 
 *Commodity
        Price
        Risk*
 
 JCP&L
        is exposed
        to market risk primarily due to fluctuations in electricity, energy transmission
        and natural gas prices. To manage the volatility relating to these exposures,
        JCP&L uses a variety of non-derivative and derivative instruments, including
        forward contracts, options, futures contracts and swaps. The derivatives
        are
        used principally for hedging purposes. Derivatives that fall within the scope
        of
        SFAS 133 must be recorded at their fair value and marked to market. The
        majority of JCP&L’s derivative hedging contracts qualify for the normal
        purchase and normal sale exception under SFAS 133 and are therefore
        excluded from the table below. Contracts that are not exempt from such treatment
        include power purchase agreements with NUG entities that were structured
        pursuant to the Public Utility Regulatory Policy Act of 1978. These non-trading
        contracts are adjusted to fair value at the end of each quarter, with a
        corresponding regulatory asset recognized for above-market costs. The change
        in
        the fair value of commodity derivative contracts related to energy production
        during the first quarter of 2006 is summarized in the following
        table:
 
 **Decrease
                  in the Fair Value of Derivative Contracts**
              
              **Non-Hedge**
              
              **Hedge**
              
              **Total*****(In
                  millions)*****Change
                  in the fair value of commodity derivative
                  contracts:**Outstanding
                  net liabilities as of January 1, 2006
              
              $
              (1,223
              )
              $
              -
              
              $
              (1,223
              )New
                  contract
                  value when entered
              
              
              -
              
              
              -
              
              
              -Additions/Changes
                  in value of existing contracts
              
              
              123
              
              
              -
              
              
              123Change
                  in
                  techniques/assumptions
              
              
              -
              
              
              -
              
              
              -Settled
                  contracts
              
              
              (73
              )
              
              -
              
              
              (73
              )**Net
                  Liabilities - Derivatives Contracts as of March 31,
                  2006**(1)
              
              **$**
              (1,173
              )
              **$**
              **-**
              
              **$**
              (1,173
              )**Impact
                  of Changes in Commodity Derivative Contracts**(2)Income
                  Statement Effects (Pre-Tax)
              
              $
              (1
              )
              $
              -
              
              $
              (1
              )Balance
                  Sheet
                  Effects:OCI
                  (Pre-Tax)
              
              $
              -
              
              $
              -
              
              $
              -Regulatory
                  Asset (Net)
              
              $
              (51
              )
              $
              -
              
              $
              (51
              )
 
 (1)
              These
                  contracts (primarily with NUGs) are offset by a regulatory
                  asset.
 (2)
              Represents
                  the
                  change in value of existing contracts, settled contracts and changes
                  in
                  techniques/ assumptions.
  123
 
 Derivatives
        are
        included on the Consolidated Balance Sheet as of March 31, 2006 as
        follows:
 
 **Balance
                  Sheet Classification**
              
              **Non-Hedge**
              
              **Hedge**
              
              **Total*****(In
                  millions)*****Current-**Other
                  Assets
              
              $
              -
              
              $
              -
              
              $
              -Other
                  liabilities
              
              
              (1
              )
              
              -
              
              
              (1
              )**Non-Current-**Other
                  Deferred
                  Charges
              
              
              11
              
              
              -
              
              
              11Other
                  noncurrent liabilities
              
              
              (1,183
              )
              
              -
              
              
              (1,183
              )**Net
                  liabilities**
              
              **$**
              **(1,173**
              )
              **$**
              **-**
              
              **$**
              **(1,173**
              )
 
 The
        valuation of
        derivative contracts is based on observable market information to the extent
        that such information is available. In cases where such information is not
        available, JCP&L relies on model-based information. The model provides
        estimates of future regional prices for electricity and an estimate of related
        price volatility. JCP&L uses these results to develop estimates of fair
        value for financial reporting purposes and for internal management decision
        making. Sources of information for the valuation of commodity derivative
        contracts as of March 31, 2006 are summarized by year in the following
        table:
 
 **Source
        of
        Information - Fair Value by Contract Year**
 
 **2006**(1)
              
              **2007**
              
              **2008**
              
              **2009**
              
              **2010**
              
              **Thereafter**
              
              **Total*****(In
                  millions)***Prices
                  actively quoted(2)
              
              $
              -
              
              $
              -
              
              $
              -
              
              $
              -
              
              $
              -
              
              $
              -
              
              $
              -Other
                  external
                  sources(3)
              
              
              (235
              )
              $
              (266
              )
              
              (231
              )
              
              -
              
              
              -
              
              
              -
              
              
              (732
              )Prices
                  based
                  on models
              
              
              -
              
              
              -
              
              
              -
              
              
              (156
              )
              
              (128
              )
              
              (157
              )
              
              (441
              )**Total****(4)**
              
              **$**
              **(235**
              **)**
              **$**
              **(266**
              **)**
              **$**
              **(231**
              **)**
              **$**
              **(156**
              **)**
              **$**
              **(128**
              **)**
              **$**
              **(157**
              **)**
              **$**
              **(1,173**
              **)**
 
 (1)  For
        the last three
        quarters of 2006.
 (2)  Exchange
        traded.
 (3)  Broker
        quote sheets.
 (4)  Includes
        $1,173
        million in non-hedge commodity derivative contracts, which are offset by
        a
        regulatory asset.
 
 JCP&L
        performs
        sensitivity analyses to estimate its exposure to the market risk of its
        commodity positions. A hypothetical 10% adverse shift in quoted market prices
        in
        the near term on both our trading and non-trading derivative instruments
        would
        not have had a material effect on JCP&L’s consolidated financial position or
        cash flows as of March 31, 2006. JCP&L estimates that if energy
        commodity prices experienced an adverse 10% change, net income for the next
        twelve months would not change, as the prices for all commodity positions
        are
        already above the contract price caps.
 
 *Equity
        Price
        Risk*
  Included in nuclear decommissioning trusts are marketable equity securities
        carried at their current fair value of approximately $88 million and $84
        million at March 31, 2006 and December 31, 2005, respectively. A
        hypothetical 10% decrease in prices quoted by stock exchanges would result
        in a
        $9 million reduction in fair value as of March 31, 2006.
 
 **Regulatory
        Matters**
 
 Regulatory
        assets
        are costs which have been authorized by the NJBPU and the FERC for recovery
        from
        customers in the future periods or for which authorization is probable. Without
        the probability of such authorization, costs currently recorded as regulatory
        assets would have been charged to income as incurred. All of JCP&L’s
        regulatory assets are expected to continue to be recovered under the provisions
        of the regulatory proceedings discussed below. JCP&L’s regulatory assets
        totaled $2.2 billion as of March 31, 2006 and December 31,
        2005.
 
 JCP&L
        is
        permitted to defer for future collection from customers the amounts by which
        its
        costs of supplying BGS to non-shopping customers and costs incurred under
        NUG
        agreements exceed amounts collected through BGS and NUGC rates and market
        sales
        of NUG energy and capacity. As of March 31, 2006, the accumulated deferred
        cost
        balance totaled approximately $558 million. New Jersey law allows for
        securitization of JCP&L's deferred balance upon application by JCP&L and
        a determination by the NJBPU that the conditions of the New Jersey restructuring
        legislation are met. On February 14, 2003, JCP&L filed for approval to
        securitize the July 31, 2003 deferred balance. On December 2, 2005,
        JCP&L filed a request for recovery of $165 million of actual
        above-market NUG costs incurred from August 1, 2003 through
        October 31, 2005 and forecasted above-market NUG costs for November and
        December 2005. On February 1, 2006, the NJBPU selected Bear Stearns as the
        financial advisor. Meetings with the NJBPU Staff and the DRA were held during
        March and April and additional discovery conducted. The DRA filed comments
        on
        April 6, 2006, arguing that the proposed securitization does not produce
        customer savings. JCP&L submitted reply comments on April 10, 2006. On
        February 23, 2006, JCP&L filed updated data reflecting actual amounts
        through December 31, 2005 of $154 million of cost incurred since
        July 31, 2003. The filing also includes a request for recovery of
        $49 million for above-market NUG costs incurred prior to August 1,
        2003, to the extent those costs are not recoverable through securitization.
        On
        March 29, 2006, a pre-hearing conference was held with the presiding ALJ.
        A
        schedule for the proceeding was established including a discovery period
        and
        evidentiary hearings scheduled for September 2006.
   124
  An
        NJBPU Decision
        and Order approving a Phase II Stipulation of Settlement and resolving the
        Motion for Reconsideration of the Phase I Order was issued on May 31, 2005.
        The
        Phase II Settlement includes a performance standard pilot program with potential
        penalties of up to 0.25% of equity return. The Order requires that JCP&L
        file quarterly reliability reports (CAIDI and SAIFI information related to
        the
        performance pilot program) through December 2006 and updates to reliability
        related project expenditures until all projects are completed. The first
        quarterly report was submitted to NJBPU on August 16, 2005. The second quarterly
        report was submitted on November 22, 2005. The third quarterly report as of
        December 31, 2005 was submitted on March 28, 2006. As of December 31, 2005
        there were no performance penalties issued by the NJBPU.
 
 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 an NJBPU order for the period June 1, 2005 through
        May 31, 2006.
 
 The
        NJBPU decision
        approving the BGS procurement proposal for the period beginning June 1,
        2006 was issued on October 12, 2005. JCP&L submitted a compliance
        filing on October 26, 2005, which was approved on November 10, 2005.
        The written Order was dated December 8, 2005. The auction took place in
        February 2006. On February 9, 2006, the NJBPU approved the auction results
        and a written order was signed on February 23, 2006. The JCP&L tariff
        compliance filing was approved on March 29, 2006. New BGS rates become effective
        June 1, 2006.
 
 In
        a reaction to the
        higher closing prices of the 2006 BGS fixed rate auction, the NJBPU, on
        March 16, 2006, initiated a generic proceeding to evaluate the auction
        process and potential options for the future. On April 6, 2006, initial
        comments were submitted. A public meeting was held on April 21, 2006 and
        a
        legislative-type hearing was held on April 28, 2006. Final comments were
        due on May 4, 2006. An NJBPU decision is anticipated in June 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 DRA filed comments on February 28, 2005
        requesting that decommissioning funding be suspended. On March 18, 2005,
        JCP&L filed a response to those comments. A schedule for further proceedings
        has not yet been set.
 
 On
        August 1,
        2005, the NJBPU established a proceeding to determine whether additional
        ratepayer protections are required at the state level in light of the recent
        repeal of PUHCA under the EPACT. An NJBPU proposed rulemaking to address
        the
        issues was published in the NJ Register on December 19, 2005. The proposal
        would prevent a holding company that owns a gas or electric public utility
        from
        investing more than 25% of the combined assets of its utility and
        utility-related subsidiaries into businesses unrelated to the utility industry.
        A public hearing was held February 7, 2006 and comments were submitted to
        the NJBPU. The
        NJBPU Staff issued a draft proposal on March 31, 2006 addressing various
        issues including access to books and records, ring-fencing, cross subsidization,
        corporate governance and related matters. Comments and reply comments are
        due by
        May 22 and May 31, 2006, respectively. JCP&L is not able to predict the
        outcome of this proceeding at this time.
 
 On
        December 21,
        2005, the NJBPU initiated a generic proceeding and requested comments in
        order
        to formulate an appropriate regulatory treatment for investment tax credits
        related to generation assets divested by New Jersey’s four electric utility
        companies. Comments were filed by the utilities and by the DRA.
 
 On
        November 18,
        2004, the FERC issued an order eliminating the regional through and out rates
        (RTOR) for transmission service between the MISO and PJM regions. The FERC
        also
        ordered the MISO, PJM and the transmission owners within the MISO and PJM to
        submit compliance filings containing a mechanism - the Seams Elimination
        Cost
        Adjustment (SECA) -- to recover lost RTOR revenues during a 16-month transition
        period from load serving entities. The FERC issued orders in 2005 setting
        the
        SECA for hearing. ATSI, JCP&L, Met-Ed, Penelec, and FES continue to be
        involved in the FERC hearings concerning the calculation and imposition of
        the
        SECA charges. The hearing began on May 1, 2006. The FERC has ordered the
        Presiding Judge to issue an initial decision by August 11,
        2006.
  125
 
 On
        January 31,
        2005, certain PJM transmission owners made three filings with the FERC pursuant
        to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and
        Penelec were parties to that proceeding and joined in two of the filings.
        In the
        first filing, the settling transmission owners submitted a filing justifying
        continuation of their existing rate design within the PJM RTO. In the second
        filing, the settling transmission owners proposed a revised Schedule 12 to
        the PJM tariff designed to harmonize the rate treatment of new and existing
        transmission facilities. Interventions and protests were filed on
        February 22, 2005. In the third filing, Baltimore Gas and Electric Company
        and Pepco Holdings, Inc. requested a formula rate for transmission service
        provided within their respective zones. On May 31, 2005, the FERC issued an
        order on these cases. First, it set for hearing the existing rate design
        and
        indicated that it will issue a final order within six months. American
        Electric
        Power Company, Inc. filed in opposition proposing to create a "postage stamp"
        rate for high voltage transmission facilities across PJM. Second, the FERC
        approved the proposed Schedule 12 rate harmonization. Third, the FERC accepted
        the proposed formula rate, subject to referral and hearing procedures. On
        June 30, 2005, the settling PJM transmission owners filed a request for
        rehearing of the May 31, 2005 order. On
        March 20, 2006 a settlement was filed with FERC in the formula rate
        proceeding that generally accepts the companies' formula rate proposal. The
        FERC
        issued an order approving this settlement on April 19, 2006. If the FERC
        accepts AEP's proposal, significant additional transmission revenues would
        be
        imposed on JCP&L, Met-Ed, Penelec, and other transmission zones within
        PJM.
 
 See
        Note 11 to
        the consolidated financial statements for further details and a complete
        discussion of regulatory matters in New Jersey.
 
 **Environmental
        Matters**
 
 JCP&L
        accrues
        environmental liabilities when it concludes that it is probable that it has
        an
        obligation for such costs and can reasonably determine the amount of such
        costs.
        Unasserted claims are reflected in JCP&L’s determination of environmental
        liabilities and are accrued in the period that they are both probable and
        reasonably estimable.
 
 JCP&L
        has been
        named as a PRP at waste disposal sites which may require cleanup under the
        Comprehensive Environmental Responsive, Comprehension and Liability Act of
        1980.
        Allegations of disposal of hazardous substances at historical sites and the
        liability involved are often unsubstantiated and subject to dispute; however,
        federal law provides that PRPs for a particular site are held liable on a
        joint
        and several basis. Therefore, environmental liabilities that are considered
        probable have been recognized on the Consolidated Balance Sheet as of
        March 31, 2006, based on estimates of the total costs of cleanup,
        JCP&L’s proportionate responsibility for such costs and the financial
        ability of other unaffiliated entities to pay. In addition, JCP&L has
        accrued liabilities for environmental remediation of former manufactured
        gas
        plants in New Jersey; those costs are being recovered by JCP&L through a
        non-bypassable SBC. Total liabilities of approximately $47.3 million have
        been accrued through March 31, 2006.
 
 See
        Note 10(B)
        to the consolidated financial statements for further details and a complete
        discussion of environmental matters.
 
 **Other
        Legal Proceedings**
 
 There
        are various
        lawsuits, claims (including claims for asbestos exposure) and proceedings
        related to JCP&L's normal business operations pending against JCP&L. The
        other material items not otherwise discussed below are described in
        Note 10(C) to the consolidated financial statements.
 
 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
        March 31, 2006 for any expenditure 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.
 
 126
 
  FirstEnergy 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 has been filed. FirstEnergy was also named, along
        with
        several other entities, in a complaint in New Jersey State Court. The
        allegations against FirstEnergy are based, in part, on an alleged failure
        to
        protect the citizens of Jersey City from an electrical power outage. No
        FirstEnergy entity serves any customers in Jersey City. A responsive pleading
        has been filed. On April 28, 2006, the Court granted FirstEnergy's motion
        to
        dismiss. It is uncertain whether the plaintiff will appeal. No estimate of
        potential liability has been undertaken in either of these matters.
 
 FirstEnergy
        is
        vigorously defending these actions, but cannot predict the outcome of any
        of
        these proceedings or whether any further regulatory proceedings or legal
        actions
        may be initiated against the Companies. Although unable to predict the impact
        of
        these proceedings, if FirstEnergy or its subsidiaries were ultimately determined
        to have legal liability in connection with these proceedings, it could have
        a
        material adverse effect on FirstEnergy's or its subsidiaries' financial
        condition, results of operations and cash flows.
 
 JCP&L's
        bargaining unit employees filed a grievance challenging JCP&L's 2002
        call-out procedure that required bargaining unit employees to respond to
        emergency power outages. On May 20, 2004, an arbitration panel concluded
        that the call-out procedure violated the parties' collective bargaining
        agreement. At the conclusion of the June 1, 2005 hearing, the 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 million to the bargaining unit employees. On February 6, 2006, the
        federal court granted a Union motion to dismiss JCP&L's appeal of the award
        as premature. JCP&L will file its appeal again in federal district court
        once the damages associated with this case are identified at an individual
        employee level. JCP&L recognized a liability for the potential
        $16 million award in 2005.
 
 The
        other material
        items not otherwise discussed above are described in Note 10(C) to the
        consolidated financial statements.
 
 **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. This EITF issue will not have a material impact on
        JCP&L's financial results.
  127
 
 *SFAS
        155 -
“Accounting for Certain Hybrid Financial Instruments-an amendment of FASB
        Statements No. 133 and 140”*
  In February 2006, the FASB issued SFAS 155 which amends SFAS 133 “Accounting for
        Derivative Instruments and Hedging Activities,” (SFAS 133) and SFAS 140
“Accounting for Transfers and Servicing of Financial Assets and Extinguishments
        of Liabilities.” This Statement permits fair value remeasurement for any hybrid
        financial instrument that contains an embedded derivative that otherwise
        would
        require bifurcation, clarifies which interest-only strips and principal-only
        strips are not subject to the requirements of SFAS 133, establishes a
        requirement to evaluate interests in securitized financial assets to identify
        interests that are freestanding derivatives or that are hybrid financial
        instruments that contain an embedded derivative requiring bifurcation, clarifies
        that concentrations of credit risk in the form of subordination are not embedded
        derivatives and amends SFAS 140 to eliminate the prohibition on a qualifying
        special-purpose entity from holding a derivative financial instrument that
        pertains to a beneficial interest other than another derivative instrument.
        This
        Statement is effective for all financial instruments acquired or issued
        beginning January 1, 2007. JCP&L is currently evaluating the impact of
        this Statement on its financial statements.
 
  128
  **METROPOLITAN
                  EDISON COMPANY****CONSOLIDATED
                  STATEMENTS OF INCOME AND COMPREHENSIVE
                  INCOME****(Unaudited)****Three
                  Months Ended****March
                  31,****2006**
              
              **2005*****(In
                  thousands)*****OPERATING
                  REVENUES**
              
              $
              311,213
              
              $
              295,781**OPERATING
                  EXPENSES AND TAXES:**Purchased
                  power
              
              
              159,887
              
              
              150,133Other
                  operating costs
              
              
              61,079
              
              
              58,430Provision
                  for
                  depreciation
              
              
              10,905
              
              
              11,521Amortization
                  of regulatory assets
              
              
              30,048
              
              
              28,621General
                  taxes
              
              
              20,621
              
              
              19,272Income
                  taxes
              
              
              6,336
              
              
              6,732Total
                  operating expenses and taxes
              
              
              288,876
              
              
              274,709**OPERATING
                  INCOME**
              
              
              22,337
              
              
              21,072**OTHER
                  INCOME (net of income taxes)**
              
              
              6,494
              
              
              6,449**NET
                  INTEREST CHARGES:**Interest
                  on
                  long-term debt
              
              
              8,717
              
              
              9,560Allowance
                  for
                  borrowed funds used during construction
              
              
              (267
              )
              
              (178
              )Other
                  interest
                  expense
              
              
              2,467
              
              
              1,663Net
                  interest
                  charges
              
              
              10,917
              
              
              11,045**NET
                  INCOME**
              
              
              17,914
              
              
              16,476**OTHER
                  COMPREHENSIVE INCOME:**Unrealized
                  gain on derivative hedges
              
              
              84
              
              
              84Income
                  tax
                  expense related to other comprehensive income
              
              
              35
              
              
              35Other
                  comprehensive income, net of tax
              
              
              49
              
              
              49**TOTAL
                  COMPREHENSIVE INCOME**
              
              $
              17,963
              
              $
              16,525The
                  preceding
                  Notes to Consolidated Financial Statements as they relate to Metropolitan
                  Edison Company arean
                  integral
                  part of these statements.
   129
  **METROPOLITAN
                    EDISON COMPANY****CONSOLIDATED
                    BALANCE SHEETS****(Unaudited)****March
                    31,**
                
                **December
                    31,****2006**
                
                **2005*****(In
                    thousands)*****ASSETS****UTILITY
                    PLANT:**In
                    service
                
                $
                1,869,720
                
                $
                1,856,425Less
                    -
                    Accumulated provision for depreciation
                
                
                721,156
                
                
                721,5661,148,564
                
                
                1,134,859Construction
                    work in progress
                
                
                21,739
                
                
                20,4371,170,303
                
                
                1,155,296**OTHER
                    PROPERTY AND INVESTMENTS:**Nuclear
                    plant
                    decommissioning trusts
                
                
                242,165
                
                
                234,854Other
                
                
                24,159
                
                
                29,678266,324
                
                
                264,532**CURRENT
                    ASSETS:**Cash
                    and cash
                    equivalents
                
                
                120
                
                
                120Notes
                    receivable from associated companies
                
                
                30,012
                
                
                27,867Receivables-Customers
                    (less accumulated provisions of $4,356,000 and $4,352,000,respectively,
                    for uncollectible accounts)
                
                
                126,917
                
                
                129,854Associated
                    companies
                
                
                13,649
                
                
                37,267Other
                
                
                7,506
                
                
                8,780Prepayments
                    and other
                
                
                47,725
                
                
                7,912225,929
                
                
                211,800**DEFERRED
                    CHARGES AND OTHER ASSETS:**Goodwill
                
                
                860,592
                
                
                864,438Regulatory
                    assets
                
                
                308,289
                
                
                309,556Prepaid
                    pension costs
                
                
                90,738
                
                
                89,005Other
                
                
                22,831
                
                
                23,0601,282,450
                
                
                1,286,059$
                2,945,006
                
                $
                2,917,687**CAPITALIZATION
                    AND LIABILITIES****CAPITALIZATION:**Common
                    stockholder's equity-Common
                    stock,
                    without par value, authorized 900,000 shares-859,000
                    shares
                    outstanding
                
                $
                1,283,268
                
                $
                1,287,093Accumulated
                    other comprehensive loss
                
                
                (1,520
                )
                
                (1,569
                )Retained
                    earnings
                
                
                48,489
                
                
                30,575Total
                    common
                    stockholder's equity
                
                
                1,330,237
                
                
                1,316,099Long-term
                    debt
                    and other long-term obligations
                
                
                591,918
                
                
                591,8881,922,155
                
                
                1,907,987**CURRENT
                    LIABILITIES:**Currently
                    payable long-term debt
                
                
                100,000
                
                
                100,000Short-term
                    borrowings-Associated
                    companies
                
                
                82,312
                
                
                140,240Other
                
                
                75,000
                
                
                -Accounts
                    payable-Associated
                    companies
                
                
                14,475
                
                
                37,220Other
                
                
                51,412
                
                
                27,507Accrued
                    taxes
                
                
                11,831
                
                
                17,911Accrued
                    interest
                
                
                9,329
                
                
                9,438Other
                
                
                20,362
                
                
                24,274364,721
                
                
                356,590**NONCURRENT
                    LIABILITIES:**Accumulated
                    deferred income taxes
                
                
                348,849
                
                
                344,929Accumulated
                    deferred investment tax credits
                
                
                9,843
                
                
                10,043Nuclear
                    fuel
                    disposal costs
                
                
                39,979
                
                
                39,567Asset
                    retirement obligation
                
                
                144,239
                
                
                142,020Retirement
                    benefits
                
                
                57,517
                
                
                57,809Other
                
                
                57,703
                
                
                58,742658,130
                
                
                653,110**COMMITMENTS
                    AND CONTINGENCIES (Note 10)**$
                2,945,006
                
                $
                2,917,687The
                    preceding
                    Notes to Consolidated Financial Statements as they relate to
                    Metropolitan
                    Edison Company are an integral part of thesebalance
                    sheets.
   130
  **METROPOLITAN
                    EDISON COMPANY****CONSOLIDATED
                    STATEMENTS OF CASH
                    FLOWS****(Unaudited)****Three
                    Months Ended****March
                    31,****2006**
                
                **2005*****(In
                    thousands)*****CASH
                    FLOWS FROM OPERATING ACTIVITIES:**Net
                    income
                
                $
                17,914
                
                $
                16,476Adjustments
                    to
                    reconcile net income to net cash from operating
                    activities-Provision
                    for
                    depreciation
                
                
                10,905
                
                
                11,521Amortization
                    of regulatory assets
                
                
                30,048
                
                
                28,621Deferred
                    costs
                    recoverable as regulatory assets
                
                
                (22,818
                )
                
                (25,271
                )Deferred
                    income taxes and investment tax credits, net
                
                
                1,704
                
                
                (11
                )Accrued
                    compensation and retirement benefits
                
                
                (3,912
                )
                
                (3,370
                )Commodity
                    derivative transactions, net
                
                
                (2,148
                )
                
                -Decrease
                    (increase) in operating assets:Receivables
                
                
                27,829
                
                
                69,712Prepayments
                    and other current assets
                
                
                (37,665
                )
                
                (34,135
                )Increase
                    (decrease) in operating liabilities:Accounts
                    payable
                
                
                1,160
                
                
                (49,591
                )Accrued
                    taxes
                
                
                (6,080
                )
                
                (9,671
                )Accrued
                    interest
                
                
                (109
                )
                
                (1,173
                )Other
                
                
                (4,649
                )
                
                (304
                )Net
                    cash
                    provided from operating activities
                
                
                12,179
                
                
                2,804**CASH
                    FLOWS FROM FINANCING ACTIVITIES:**New
                    Financing-Short-term
                    borrowings, net
                
                
                17,065
                
                
                28,587Redemptions
                    and Repayments-Long-term
                    debt
                
                
                -
                
                
                (435
                )Dividend
                    Payments-Common
                    stock
                
                
                -
                
                
                (9,000
                )Net
                    cash
                    provided from financing activities
                
                
                17,065
                
                
                19,152**CASH
                    FLOWS FROM INVESTING ACTIVITIES:**Property
                    additions
                
                
                (25,277
                )
                
                (16,199
                )Proceeds
                    from
                    nuclear decommissioning trust fund sales
                
                
                42,061
                
                
                22,667Investments
                    in
                    nuclear decommissioning trust funds
                
                
                (44,432
                )
                
                (25,038
                )Loans
                    to
                    associated companies, net
                
                
                (2,145
                )
                
                (3,150
                )Other
                
                
                549
                
                
                (236
                )Net
                    cash used
                    for investing activities
                
                
                (29,244
                )
                
                (21,956
                )Net
                    change in
                    cash and cash equivalents
                
                
                -
                
                
                -Cash
                    and cash
                    equivalents at beginning of period
                
                
                120
                
                
                120Cash
                    and cash
                    equivalents at end of period
                
                $
                120
                
                $
                120The
                    preceding
                    Notes to Consolidated Financial Statements as they relate to
                    Metropolitan
                    Edison Company are anintegral
                    part
                    of these statements.
  131
   ***Report
        of Independent Registered Public Accounting Firm***
 
 
 
 
 
 
 
 
 
 To
        the Stockholder
        and Board of
 Directors
        of
        Metropolitan Edison Company:
 
 We
        have reviewed the
        accompanying consolidated balance sheet of Metropolitan Edison Company and
        its
        subsidiaries as of March 31, 2006 and the related consolidated statements
        of income, comprehensive income and cash flows for each of the three-month
        periods ended March 31, 2006 and 2005. These interim financial statements
        are
        the responsibility of the Company’s management.
 
 We
        conducted our
        review in accordance with the standards of the Public Company Accounting
        Oversight Board (United States). A review of interim financial information
        consists principally of applying analytical procedures and making inquiries
        of
        persons responsible for financial and accounting matters. It is substantially
        less in scope than an audit conducted in accordance with the standards of
        the
        Public Company Accounting Oversight Board, the objective of which is the
        expression of an opinion regarding the financial statements taken as a whole.
        Accordingly, we do not express such an opinion.
 
 Based
        on our review,
        we are not aware of any material modifications that should be made to the
        accompanying consolidated interim financial statements for them to be in
        conformity with accounting principles generally accepted in the United States
        of
        America.
 
 We
        previously
        audited, in accordance with the standards of the Public Company Accounting
        Oversight Board (United States), the consolidated balance sheet as of December
        31, 2005, and the related consolidated statements of income, capitalization,
        common stockholder’s equity, preferred stock, cash flows and taxes for the year
        then ended (not presented herein), and in our report (which contained references
        to the Company’s change in its method of accounting for asset retirement
        obligations as of January 1, 2003 and conditional asset retirement obligations
        as of December 31, 2005 as discussed in Note 2(G) and Note 9 to those
        consolidated financial statements) dated February 27, 2006, we expressed an
        unqualified opinion on those consolidated financial statements. In our opinion,
        the information set forth in the accompanying consolidated balance sheet
        as of
        December 31, 2005, is fairly stated in all material respects in relation
        to the
        consolidated balance sheet from which it has been derived.
 
 
 
 
 PricewaterhouseCoopers
        LLP
 Cleveland,
        Ohio
 May
        8,
        2006
 
  132
  **METROPOLITAN
        EDISON COMPANY**
 
 **MANAGEMENT’S
        DISCUSSION AND ANALYSIS OF**
 **RESULTS
        OF
        OPERATIONS AND FINANCIAL CONDITION**
 
 
 Met-Ed is a wholly owned, electric utility subsidiary of FirstEnergy. Met-Ed
        conducts business in eastern Pennsylvania, providing regulated electric
        transmission and distribution services. Met-Ed also provides generation service
        to those customers electing to retain Met-Ed as their power supplier.
 
 **Results
        of Operations**
 
 Net Income in the first quarter of 2006 increased to $18 million from $16
        million in the first quarter of 2005. This increase was primarily due to
        higher
        operating revenues and lower depreciation expense, and was partially offset
        by
        increases in purchased power costs, other operating costs, amortization of
        regulatory assets and general taxes.
 
 Operating revenues increased by $15 million, or 5.2% in the first quarter
        of
        2006 compared with the same period in 2005 primarily due to higher retail
        generation revenues, transmission revenues and other operating revenues,
        partially offset by lower distribution revenues. Retail generation revenues
        increased in all customer sectors by $12 million principally due to higher
        composite unit prices and a 12.1% increase in industrial KWH sales. The
        industrial sales increase resulted from reduced generation service provided
        by
        alternative suppliers. Sales by alternative suppliers as a percent of total
        industrial sales in Med-Ed's franchise area decreased by 13.7 percentage
        points
        in the first quarter of 2006.
 
 Revenues from distribution throughput decreased by $2 million, primarily
        due to
        a 2.4% decrease in KWH deliveries, reflecting the effect of milder temperatures
        in 2006 compared with 2005, as demonstrated by a 16.4% decrease in heating
        degree days, partially offset by slightly higher composite unit prices.
        Transmission revenues increased by $3 million primarily due to higher
        transmission prices, which also resulted in higher transmission expenses
        as
        discussed below. Other operating revenues also increased due to a $2 million
        increase in the first quarter of 2006, compared with the first quarter of
        2005,
        in the 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 specified levels, which occurred. This
        payment is credited to Met-Ed’s customers, resulting in no net earnings effect.
 
 Changes in KWH sales by customer class in the first quarter of 2006 compared
        to
        the same period of 2005 are summarized in the following table:
 
 **Changes
                  in KWH Sales****Increase
                  (Decrease)**Retail
                  Electric Generation:Residential
              
              
              (2.5
              %)Commercial
              
              
              0.1
              %Industrial
              
              
              12.1
              %**Total
                  Retail Electric Generation Sales**
              
              
              2.0
              %Distribution
                  Deliveries:Residential
              
              
              (2.7
              %)Commercial
              
              
              (0.8
              %)Industrial
              
              
              (3.6
              %)**Total
                  Distribution Deliveries**
              
              
              (2.4
              %)
 
 *Operating
        Expenses and Taxes*
 
 Total
        operating
        expenses and taxes increased by $14 million, or 5.2% in the first quarter
        of
        2006 compared to the first quarter of 2005. The following table presents
        changes
        from the prior year by expense category:
 
 **Operating
                  Expenses and Taxes - Changes (In millions)****Increase
                  (Decrease)**Purchased
                  power costs
              
              $
              10Other
                  operating costs
              
              
              3Provision
                  for
                  depreciation
              
              
              (1
              )Amortization
                  of regulatory assets
              
              
              1General
                  taxes
              
              
              1Income
                  taxes
              
              
              -**Total
                  operating expenses and taxes**
              
              $
              14
 
  133
 
 Purchased power costs increased by $10 million in the first quarter of 2006
        as
        compared with the same period of 2005. The increase was mainly attributable
        to a
        2.1% increase in KWH purchases to meet higher retail generation demand
        requirements. The effect of the increased power purchases was partially offset
        by lower composite unit prices. NUG contract purchases also increased by
        $2
        million. Other operating costs increased in the first quarter of 2006 primarily
        due to higher transmission expenses, which increased as a result of the higher
        transmission prices discussed above. Amortization of regulatory assets increased
        principally due to a higher level of CTC revenue recovery, partially offset
        by
        lower amortization of non-NUG stranded costs. General taxes increased by
        $1 million in the first quarter of 2006 primarily due to higher gross
        receipt taxes.
 
 **Capital
        Resources and Liquidity**
 
 Met-Ed’s cash requirements in 2006 for operating expenses, construction
        expenditures and scheduled debt maturities, are expected to be met with a
        combination of cash from operations and short-term credit
        arrangements.
 
 *Changes
        in Cash
        Position*
 
 As of March 31, 2006 and December 31, 2005, Met-Ed had $120,000 of cash and
        cash equivalents.
 
 *Cash
        Flows From
        Operating Activities*
 
 Cash provided from operating activities in the first quarter of 2006 and
        2005
        were as follows:
 
 **Three
                  Months Ended**
                **March
                  31,****Operating
                  Cash Flows**
              
              **2006**
              
              **2005*****(In
                  millions)***Cash
                  earnings(1)
              
              $
              32
              
              $
              28Working
                  capital and other
              
              
              (20
              )
              
              (25
              )Net
                  cash
                  provided from operating activities
              
              $
              12
              
              $
              3
 
 (1)  Cash
        earnings is a
        non-GAAP measure (see reconciliation below).
  Cash earnings (in the table above) are not a measure of performance calculated
        in accordance with GAAP. Met-Ed believes that cash earnings are a useful
        financial measure because it provides investors and management with an
        additional means of evaluating its cash-based operating
        performance.
 
 **Three
                  Months Ended****March
                  31,****Reconciliation
                  of Cash Earnings**
              
              **2006**
              
              **2005*****(In
                  millions)***Net
                  Income
                  (GAAP)
              
              $
              18
              
              $
              16Non-Cash
                  Charges (Credits):Provision
                  for
                  depreciation
              
              
              11
              
              
              12Amortization
                  of regulatory assets
              
              
              30
              
              
              29Deferred
                  costs
                  recoverable as regulatory assets
              
              
              (23
              )
              
              (25
              )Deferred
                  income taxes and investment tax credits, net
              
              
              2
              
              
              -Commodity
                  derivative transactions, net
              
              
              (2
              )
              
              -Other
                  non-cash
                  expenses
              
              
              (4
              )
              
              (4
              )Cash
                  earnings
                  (Non-GAAP)
              
              $
              32
              
              $
              28
  The $4 million increase in cash earnings is described above under “Results
        of Operations.” The $5 million working capital change primarily resulted
        from decreased outflows of $51 million in accounts payable and
        $1 million in accrued interest, partially offset by a $42 million
        decrease in cash provided from the settlement of receivables and a
        $5 million decrease in other accrued liabilities.
 
 *Cash
        Flows From
        Financing Activities*
 
 Net cash provided from financing activities was $17 million in the first
        quarter
        of 2006 compared to $19 million in the first quarter of 2005. The decrease
        primarily reflects an $11 million decrease in short-term borrowings in the
        first
        quarter of 2006, partially offset by a $9 million decrease in common stock
        dividend payments to FirstEnergy.
  134
 
 As of March 31, 2006, Met-Ed had approximately $30 million of cash and temporary
        investments (which included short-term notes receivable from associated
        companies) and $157 million of short-term borrowings. Met-Ed has authorization
        from the SEC, continued by FERC rules adopted as a result of EPACT's repeal
        of
        PUHCA, to incur short-term debt up to $250 million and authorization from
        the
        PPUC to incur money pool borrowings up to $300 million. In addition, Met-Ed
        has $80 million of available accounts receivable financing facilities as
        of
        March 31, 2006 from Met-Ed Funding LLC, Met-Ed’s wholly owned subsidiary.
        As a separate legal entity with separate creditors, Met-Ed Funding would
        have to
        satisfy its obligations to creditors before any of its remaining assets could
        be
        made available to Met-Ed. As of March 31, 2006 the facility was drawn for
        $75 million.
 
 Under the terms of Met-Ed’s senior note indenture, FMB may no longer be issued
        so long as the senior bonds are outstanding. As of March 31, 2006, Met-Ed
        had the capability to issue $625 million of additional senior notes based
        upon FMB collateral. Met-Ed had no restrictions on the issuance of preferred
        stock.
 
 Met-Ed, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Penelec, FES and ATSI, as
        Borrowers, have entered into a syndicated $2 billion five-year revolving
        credit facility with a syndicate of banks which expires in June 2010. 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 expiration
        date, as the same may be extended. Met-Ed’s borrowing limit under the facility
        is $250 million.
 
 Under the revolving credit facility, Borrowers may request the issuance of
        LOC
        expiring up to one year from the date of issuance. The stated amount of
        outstanding LOCs will count against total commitments available under the
        facility and against the applicable borrower’s borrowing sub-limit. Total unused
        borrowing capability under the existing credit facilities and accounts
        receivable financing facilities totaled $255 million.
 
 The revolving credit facility contains financial covenants requiring each
        Borrower to maintain a consolidated debt to total capitalization ratio of
        no
        more than 65%. As of March 31, 2006, Met-Ed’s debt to total capitalization
        as defined under the revolving credit facility was 39%.
 
 The facility does not contain any provisions that either restrict Met-Ed’s
        ability to borrow or accelerate repayment of outstanding advances as a result
        of
        any change in its credit ratings. Pricing is defined in “pricing grids”, whereby
        the cost of funds borrowed under the facility is related to Met-Ed's credit
        ratings.
 
 Met-Ed has the ability to borrow from its regulated affiliates and FirstEnergy
        to meet its short-term working capital requirements. FESC administers this
        money
        pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries,
        as
        well as proceeds available from bank borrowings. Companies receiving a loan
        under the money pool agreements must repay the principal amount of such a
        loan,
        together with accrued interest, within 364 days of borrowing the funds. The
        rate
        of interest is the same for each company receiving a loan from the pool and
        is
        based on the average cost of funds available through the pool. The average
        interest rate for borrowings in the first quarter of 2006 was
        4.58%.
 
 Met-Ed’s access to the capital markets and the costs of financing are dependent
        on the ratings of its securities and that of FirstEnergy. As of March 31,
        2006,
        Met-Ed’s and FirstEnergy’s ratings outlook from S&P on all securities was
        stable. The ratings outlook from Moody’s and Fitch on all securities is
        positive.
 
 *Cash
        Flows From
        Investing Activities*
 
 In the first quarter of 2006, Met-Ed's cash used for investing activities
        totaled $29 million, compared to $22 million in the first quarter of
        2005. The increase primarily resulted from a $9 million increase in property
        additions, partially offset by a decrease in loans to associated companies.
        Expenditures for property additions primarily support Met-Ed’s energy delivery
        operations and reliability initiatives.
 
 During the remaining three quarters of 2006, capital requirements for property
        additions are expected to be about $56 million. Met-Ed has additional
        requirements of approximately $100 million for maturing long-term debt
        during the remainder of 2006. These cash requirements are expected to be
        satisfied from a combination of internal cash, funds raised in the long-term
        debt capital markets and short-term credit arrangements.
 
 Met-Ed's capital spending for the period 2006 through 2010 is expected to
        be
        about $366 million, of which approximately $82 million applies to
        2006. The capital spending is primarily for property additions supporting
        the
        distribution of electricity.
  135
 
 **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 oversight to risk management activities throughout the
        company.
 
 *Commodity
        Price
        Risk*
 
 Met-Ed is exposed to market risk primarily due to fluctuations in electricity,
        energy transmission, natural gas, coal, and emission prices. To manage the
        volatility relating to these exposures, it uses a variety of non-derivative
        and
        derivative instruments, including forward contracts, options, futures contracts,
        and swaps. The derivatives are used principally for hedging purposes. All
        derivatives that fall within the scope of SFAS 133 must be recorded at their
        fair value and marked to market. The majority of Met-Ed’s derivative hedging
        contracts qualify for normal purchase and normal sale exception under SFAS
        133.
        Contracts that are not exempt from such treatment include purchase power
        agreements with NUG entities that were structured pursuant to the Public
        Utility
        Regulatory Policy Act of 1978. These non-trading contracts are adjusted to
        fair
        value at the end of each quarter, with a corresponding regulatory asset
        recognized for above-market costs. The change in the fair value of commodity
        derivative contracts related to energy production during the first quarter
        of
        2006 is summarized in the following table:
 
 **Three
                  Months Ended****March
                  31, 2006****Increase
                  (Decrease) in the Fair Value of Derivative
                  Contracts**
              
              **Non-Hedge**
              
              **Hedge**
              
              **Total*****(In
                  millions)***Change
                  in the
                  fair value of commodity derivative contractsOutstanding
                  net asset as of January 1, 2006
              
              $
              27
              
              $
              -
              
              $
              27New
                  contract
                  value when entered
              
              
              -
              
              
              -
              
              
              -Additions/Changes
                  in value of existing contracts
              
              
              4
              
              
              -
              
              
              4Change
                  in
                  techniques/assumptions
              
              
              -
              
              
              -
              
              
              -Settled
                  contracts
              
              
              (7
              )
              
              -
              
              
              (7
              )**Net
                  Assets - Derivatives Contracts as of March 31, 2006**(1)
              
              **$**
              **24**
              
              **$**
              **-**
              
              **$**
              **24****Impact
                  of Changes in Commodity Derivative Contracts**(2)Income
                  Statement Effects (Pre-Tax)
              
              $
              2
              
              $
              -
              
              $
              2Balance
                  Sheet
                  Effects:OCI
                  (Pre-Tax)
              
              $
              -
              
              $
              -
              
              $
              -Regulatory
                  Liability
              
              $
              5
              
              $
              -
              
              $
              5
 
 (1)  Includes
        $21 million in non-hedge commodity derivative contracts, which are offset
        by a regulatory liability.
 (2)  Represents
        the
        change in value of existing contracts, settled contracts and changes in
        techniques/ assumptions
 
 Derivatives
        are
        included on the Consolidated Balance Sheet as of March 31, 2006 as
        follows :
 
 **Non-Hedge**
              
              **Hedge**
              
              **Total*****(In
                  millions)*****Current-**Other
                  assets
              
              $
              2
              
              $
              -
              
              $
              2Other
                  liabilities
              
              
              -
              
              
              -
              
              
              -**Non-Current-**Other
                  deferred
                  charges
              
              
              23
              
              
              -
              
              
              23Other
                  noncurrent liabilities
              
              
              (1
              )
              
              -
              
              
              (1
              )**Net
                  assets**
              
              **$**
              **24**
              
              **$**
              **-**
              
              **$**
              **24**
 
  136
 
 The valuation of derivative contracts is based on observable market information
        to the extent that such information is available. In cases where such
        information is not available, Met-Ed relies on model-based information. The
        model provides estimates of future regional prices for electricity and an
        estimate of related price volatility. Met-Ed uses these results to develop
        estimates of fair value for financial reporting purposes and for internal
        management decision making. Sources of information for the valuation of
        commodity derivative contracts as of March 31, 2006 are summarized by year
        in the following table:
 
 **Source
                  of Information****-
                  Fair
                  Value by Contract Year**
              
              **2006**(1)
              
              **2007**
              
              **2008**
              
              **2009**
              
              **2010**
              
              **Thereafter**
              
              **Total*****(In
                  millions)***Prices
                  based
                  on external sources(2)
              
              $
              (20
              )
              $
              (16
              )
              $
              (17
              )
              $
              -
              
              $
              -
              
              $
              -
              
              $
              (53
              )Prices
                  based
                  on models(3)
              
              
              -
              
              
              -
              
              
              -
              
              
              (16
              )
              
              (12
              )
              
              105
              
              
              77**Total**
              
              **$**
              (20
              )
              **$**
              (16
              )
              **$**
              (17
              )
              **$**
              (16
              )
              **$**
              (12
              )
              **$**
              **105**
              
              **$**
              **24**
 
 (1)  For
        the last three
        quarters of 2006.
 (2)  Broker
        quote
        sheets
 (3)  Includes
        $21 million
        from an embedded option that is offset by a regulatory liability and does
        not
        affect earnings.
 
 Met-Ed performs sensitivity analyses to estimate its exposure to the market
        risk
        of its commodity positions. A hypothetical 10% adverse shift in quoted market
        prices in the near term on both of Met-Ed’s trading and non-trading derivative
        instruments would not have had a material effect on its consolidated financial
        position or cash flows as of March 31, 2006.
 
 *Equity
        Price
        Risk*
 
 Included in Met-Ed's nuclear decommissioning trusts are marketable equity
        securities carried at their market value of approximately $148 million and
        $142 million as of March 31, 2006 and December 31, 2005, respectively. A
        hypothetical 10% decrease in prices quoted by stock exchanges would result
        in a
        $15 million reduction in fair value as of March 31, 2006.
 
 **Regulatory
        Matters**
  Regulatory
        assets
        are costs which have been authorized by the PPUC and the FERC for recovery
        from
        customers in the future periods or for which authorization is probable. Without
        the probability of such authorization, costs currently recorded as regulatory
        assets would have been charged to income as incurred. All regulatory assets
        are
        expected to be recovered under the provisions of Met-Ed’s transition plan and
        rate restructuring plan. Met-Ed’s regulatory assets as of March 31, 2006
        and December 31, 2005 were $308 million and $310 million,
        respectively.
 
 Met-Ed’s
        and
        Penelec’s combined portion of total merger savings during 2001 - 2004 is
        estimated to be approximately $51 million. A procedural schedule was
        established by the ALJ on January 17, 2006. Met-Ed and Penelec filed
        initial testimony on March 1, 2006. Hearings are currently scheduled for
        the end of October 2006 with the ALJ’s recommended decision to be issued in
        February 2007. Met-Ed and Penelec have requested that this proceeding be
        consolidated with the April 10, 2006 transition plan filing proceeding
        discussed below. Met-Ed is unable to predict the outcome of this
        proceeding.
 
 In
        an
        October 16, 2003 order, the PPUC approved September 30, 2004 as the
        date for Met-Ed's and Penelec's NUG trust fund refunds. The PPUC order also
        denied their accounting treatment request regarding the CTC rate/shopping
        credit
        swap by requiring Met-Ed and Penelec to treat the stipulated CTC rates that
        were
        in effect from January 1, 2002 on a retroactive basis. On October 22,
        2003, Met-Ed and Penelec filed an Objection with the Commonwealth Court asking
        that the Court reverse this PPUC finding; a Commonwealth Court judge
        subsequently denied their Objection on October 27, 2003 without
        explanation. On October 31, 2003, Met-Ed and Penelec filed an Application
        for Clarification of the Court order with the Commonwealth Court, a Petition
        for
        Review of the PPUC's October 2 and October 16, 2003 Orders, and an
        Application for Reargument, if the judge, in his clarification order, indicates
        that Met-Ed's and Penelec's Objection was intended to be denied on the merits.
        The Reargument Brief before the Commonwealth Court was filed on January 28,
        2005. Oral arguments are scheduled for June 8, 2006.
 
 On
        November 18,
        2004, the FERC issued an order eliminating the regional through and out rates
        (RTOR) for transmission service between the MISO and PJM regions. The FERC
        also
        ordered the MISO, PJM and the transmission owners within the MISO and PJM
        to
        submit compliance filings containing a mechanism - the Seams Elimination
        Cost
        Adjustment (SECA) -- to recover lost RTOR revenues during a 16-month transition
        period from load serving entities. The FERC issued orders in 2005 setting
        the
        SECA for hearing. ATSI, JCP&L, Met-Ed, Penelec, and FES continue to be
        involved in the FERC hearings concerning the calculation and imposition of
        the
        SECA charges. The hearing began on May 1, 2006. The FERC has ordered the
        Presiding Judge to issue an initial decision by August 11,
        2006.
  137
 
 On
        January 31,
        2005, certain PJM transmission owners made three filings with the FERC pursuant
        to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and
        Penelec were parties to that proceeding and joined in two of the filings.
        In the
        first filing, the settling transmission owners submitted a filing justifying
        continuation of their existing rate design within the PJM RTO. In the second
        filing, the settling transmission owners proposed a revised Schedule 12 to
        the PJM tariff designed to harmonize the rate treatment of new and existing
        transmission facilities. Interventions and protests were filed on
        February 22, 2005. In the third filing, Baltimore Gas and Electric Company
        and Pepco Holdings, Inc. requested a formula rate for transmission service
        provided within their respective zones. On May 31, 2005, the FERC issued an
        order on these cases. First, it set for hearing the existing rate design
        and
        indicated that it will issue a final order within six months. American
        Electric
        Power Company, Inc. filed in opposition proposing to create a "postage stamp"
        rate for high voltage transmission facilities across PJM. Second, the FERC
        approved the proposed Schedule 12 rate harmonization. Third, the FERC accepted
        the proposed formula rate, subject to referral and hearing procedures. On
        June 30, 2005, the settling PJM transmission owners filed a request for
        rehearing of the May 31, 2005 order. On
        March 20, 2006 a settlement was filed with FERC in the formula rate
        proceeding that generally accepts the companies' formula rate proposal. The
        FERC
        issued an order approving this settlement on April 19, 2006. If the FERC
        accepts AEP's proposal, significant additional transmission revenues would
        be
        imposed on JCP&L, Met-Ed, Penelec, and other transmission zones within
        PJM.
 
 As
        of March 31,
        2006, Met-Ed's and Penelec's regulatory deferrals pursuant to the 1998
        Restructuring Settlement (including the Phase 2 Proceedings) and the
        FirstEnergy/GPU Merger Settlement Stipulation are $328 million and
        $50 million, respectively. Penelec's $50 million is subject to the pending
        resolution of taxable income issues associated with NUG trust fund proceeds.
 
 On January 12, 2005, Met-Ed filed, before the PPUC, a request for deferral
        of
        transmission-related costs beginning January 1, 2005. The OCA, OSBA, OTS,
        MEIUG,
        PICA, Allegheny Electric Cooperative and Pennsylvania Rural Electric Association
        have all intervened in the case. As of March 31, 2006, the PPUC had taken
        no
        action on the request and Met-Ed had not yet implemented deferral accounting
        for
        these costs. Met-Ed sought to consolidate this proceeding (and modified its
        request to provide deferral of 2006 transmission-related costs only) with
        the
        comprehensive rate filing it made on April 10, 2006 as described below. On
        May 4, 2006, the PPUC approved the modified request. Accordingly, Met-Ed
        will
        implement deferral accounting for these costs in the second quarter of 2006,
        which will include $24 million representing the amount that was
        incurred in the first quarter of 2006 -- the deferral of such amount will
        be reflected in the second quarter of 2006.
 
 Met-Ed
        and Penelec
        purchase a portion of their PLR requirements from FES through a wholesale
        power
        sales agreement. Under this agreement, FES retains the supply obligation
        and the
        supply profit and loss risk for the portion of power supply requirements
        not
        self-supplied by Met-Ed and Penelec under their contracts with NUGs and other
        unaffiliated suppliers. The FES arrangement reduces Met-Ed's and Penelec's
        exposure to high wholesale power prices by providing power at a fixed price
        for
        their uncommitted PLR energy costs during the term of the agreement with
        FES.
        The wholesale power sales agreement with FES could automatically be extended
        for
        each successive calendar year unless any party elects to cancel the agreement
        by
        November 1 of the preceding year. On November 1, 2005, FES and the other
        parties thereto amended the agreement to provide FES the right in 2006 to
        terminate the agreement at any time upon 60 days notice. On April 7, 2006,
        the parties to the wholesale power sales agreement entered into a Tolling
        Agreement that arises out of FES’ notice to Met-Ed and Penelec that FES elected
        to exercise its right to terminate the wholesale power sales agreement effective
        midnight December 31, 2006, because that agreement is not economically
        sustainable to FES.
 
 In
        lieu of allowing
        such termination to become effective as of December 31, 2006, the parties
        agreed, pursuant to the Tolling Agreement, to amend the wholesale power sales
        agreement to provide as follows:
 
 1.  The
        termination
        provisions of the wholesale power sales agreement will be tolled for one
        year
        until December 31, 2007, provided that during such tolling
        period:
 
 a.
            FES
                will be
                permitted to terminate the wholesale power sales agreement at any
                time
                with sixty days written notice; b.
            Met-Ed
                and
                Penelec will procure through arrangements other than the wholesale
                power
                sales agreement beginning December 1, 2006 and ending December 31,
                2007,
                approximately 33% of the amounts of capacity and energy necessary
                to
                satisfy their PLR obligations for which Committed Resources (i.e.,
                non-utility generation under contract to Met-Ed and Penelec, Met-Ed-
                and
                Penelec-owned generating facilities, purchased power contracts and
                distributed generation) have not been obtained;
                and c.
            FES
                will not
                be obligated to supply additional quantities of capacity and energy
                in the
                event that a supplier of Committed Resources defaults on its supply
                agreement.  138
  
 2.  During
        the tolling
        period FES will not act as agent for Met-Ed or Penelec in procuring the services
        under section 1.(b) above; and
 
 3.  The
        pricing
        provision of the wholesale power sales agreement shall remain unchanged provided
        Met-Ed and Penelec comply with the provisions of the Tolling Agreement and
        any
        applicable provision of the wholesale power sales agreement.
 
 In
        the event that
        FES elects not to terminate the wholesale power sales agreement effective
        midnight December 31, 2007, similar tolling agreements effective after
        December 31, 2007 are expected to be considered by FES for subsequent years
        if
        Met-Ed and Penelec procure through arrangements other than the wholesale
        power
        sales agreement approximately 64%, 83% and 95% of the additional amounts
        of
        capacity and energy necessary to satisfy their PLR obligations for 2008,
        2009
        and 2010, respectively, for which Committed Resources have not been obtained
        from the market.
 
 The
        wholesale power
        sales agreement, as modified by the Tolling Agreement, requires Met-Ed and
        Penelec to satisfy the portion of their PLR obligations currently supplied
        by
        FES from unaffiliated suppliers at prevailing prices, which are likely to
        be
        higher than the current price charged by FES under the current agreement
        and, as
        a result, Met-Ed’s and Penelec’s purchased power costs could materially
        increase. If Met-Ed and Penelec were to replace the entire FES supply at
        current
        market power prices without corresponding regulatory authorization to increase
        their generation prices to customers, each company would likely incur a
        significant increase in operating expenses and experience a material
        deterioration in credit quality metrics. Under such a scenario, each company's
        credit profile would no longer be expected to support an investment grade
        rating
        for its fixed income securities. There can be no assurance, however, that
        if FES
        ultimately determines to terminate, or significantly modify the agreement,
        timely regulatory relief will be granted by the PPUC pursuant to the April
        10,
        2006 comprehensive rate filing discussed below, or, to the extent granted,
        adequate to mitigate such adverse consequences.
 
 Met-Ed
        and Penelec
        made a comprehensive rate filing with the PPUC on April 10, 2006 that
        addresses a number of transmission, distribution and supply issues. If Met-Ed's
        and Penelec's preferred approach involving accounting deferrals is approved,
        the
        filing would increase annual revenues by $216 million and $157 million,
        respectively. That filing includes, among other things, a request to charge
        customers for an increasing amount of market priced power procured through
        a
        competitive bid process as the amount of supply provided under the existing
        FES
        agreement is phased out in accordance with the April 7, 2006 Tolling agreement
        described above. Met-Ed
        and Penelec
        also requested approval of the January 12, 2005 petition for the deferral
        of
        transmission-related costs discussed above, but only for those costs incurred
        during 2006. In this rate filing, Met-Ed and Penelec also requested recovery
        of
        annual transmission and related costs incurred on or after January 1, 2007,
        plus the amortized portion of 2006 costs over a ten-year period, along with
        applicable carrying charges, through an adjustable rider similar to that
        implemented in Ohio. Changes in the
        recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs
        are
        also included in the filing. The filing contemplates a reduction in distribution
        rates for Met-Ed in the amount of $37 million annually and an increase in
        distribution rates for Penelec in the amount of $20 million annually. Although
        the companies have proposed an effective date of June 10, 2006, it is
        expected that the PPUC will suspend the effective date for seven months as
        permitted under Pennsylvania law. Hearings are expected to be scheduled for
        the
        second half of 2006 and a PPUC decision is expected early in the first quarter
        of 2007.
 
 See Note 11 to the consolidated financial statements for further details
        and a complete discussion of regulatory matters in Pennsylvania including
        a more
        detailed discussion of reliability initiatives, including actions by the
        PPUC
        that impact Met-Ed .
 
 **Environmental
        Matters**
 
 Met-Ed
        accrues
        environmental liabilities when it concludes that it is probable that it has
        an
        obligation for such costs and can reasonably determine the amount of such
        costs.
        Unasserted claims are reflected in Met-Ed’s determination of environmental
        liabilities and are accrued in the period that they are both probable and
        reasonably estimable.
 
 Met-Ed
        has been
        named as a PRP at waste disposal sites which may require cleanup under the
        Comprehensive Environmental Responsive, Comprehension and Liability Act of
        1980.
        Allegations of disposal of hazardous substances at historical sites and the
        liability involved are often unsubstantiated and subject to dispute; however,
        federal law provides that PRPs for a particular site are held liable on a
        joint
        and several basis. Therefore, environmental liabilities that are considered
        probable have been recognized on the Consolidated Balance Sheet as of
        March 31, 2006, based on estimates of the total costs of cleanup, Met-Ed’s
        proportionate responsibility for such costs and the financial ability of
        other
        unaffiliated entities to pay.
  139
 
 See
        Note 10(B)
        to the consolidated financial statements for further details and a complete
        discussion of environmental matters.
 
 **Other
        Legal Matters**
 
 There
        are various
        lawsuits, claims (including claims for asbestos exposure) and proceedings
        related to Met-Ed’s normal business operations pending against Met-Ed. The other
        material items not otherwise discussed below are described in Note 10(C) to
        the consolidated financial statements.
 
 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
        March 31, 2006 for any expenditure 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
        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
        has
        been filed. FirstEnergy was also named, along with several other entities,
        in a
        complaint in New Jersey State Court. The allegations against FirstEnergy
        are
        based, in part, on an alleged failure to protect the citizens of Jersey City
        from an electrical power outage. No FirstEnergy entity serves any customers
        in
        Jersey City. A responsive pleading has been filed. On April 28, 2006, the
        Court
        granted FirstEnergy's motion to dismiss. It is uncertain whether the plaintiff
        will appeal. No estimate of potential liability has been undertaken in either
        of
        these matters.
 
 FirstEnergy
        is
        vigorously defending these actions, but cannot predict the outcome of any
        of
        these proceedings or whether any further regulatory proceedings or legal
        actions
        may be initiated against the Companies. Although unable to predict the impact
        of
        these proceedings, if FirstEnergy or its subsidiaries were ultimately determined
        to have legal liability in connection with these proceedings, it could have
        a
        material adverse effect on FirstEnergy's or its subsidiaries' financial
        condition, results of operations and cash flows.
  140
  
 **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. This EITF issue will not have a material impact on Met-Ed's
        financial results.
 
 *SFAS
        155 -
“Accounting for Certain Hybrid Financial Instruments-an amendment of FASB
        Statements No. 133 and 140”*
  In February 2006, the FASB issued SFAS 155 which amends SFAS 133 “Accounting for
        Derivative Instruments and Hedging Activities,” (SFAS 133) and SFAS 140
“Accounting for Transfers and Servicing of Financial Assets and Extinguishments
        of Liabilities.” This Statement permits fair value remeasurement for any hybrid
        financial instrument that contains an embedded derivative that otherwise
        would
        require bifurcation, clarifies which interest-only strips and principal-only
        strips are not subject to the requirements of SFAS 133, establishes a
        requirement to evaluate interests in securitized financial assets to identify
        interests that are freestanding derivatives or that are hybrid financial
        instruments that contain an embedded derivative requiring bifurcation, clarifies
        that concentrations of credit risk in the form of subordination are not embedded
        derivatives and amends SFAS 140 to eliminate the prohibition on a qualifying
        special-purpose entity from holding a derivative financial instrument that
        pertains to a beneficial interest other than another derivative instrument.
        This
        Statement is effective for all financial instruments acquired or issued
        beginning January 1, 2007. Met-Ed is currently evaluating the impact of
        this Statement on its financial statements.
 
 
  141
  **PENNSYLVANIA
                    ELECTRIC COMPANY****CONSOLIDATED
                    STATEMENTS OF INCOME AND COMPREHENSIVE
                    INCOME****(Unaudited)****Three
                    Months Ended****March
                    31,****2006**
                
                **2005*****(In
                    thousands)*****OPERATING
                    REVENUES**
                
                $
                291,752
                
                $
                293,929**OPERATING
                    EXPENSES AND TAXES:**Purchased
                    power
                
                
                161,641
                
                
                150,277Other
                    operating costs
                
                
                38,342
                
                
                53,793Provision
                    for
                    depreciation
                
                
                12,643
                
                
                12,506Amortization
                    of regulatory assets
                
                
                14,815
                
                
                13,185General
                    taxes
                
                
                19,389
                
                
                18,206Income
                    taxes
                
                
                12,764
                
                
                15,792Total
                    operating expenses and taxes
                
                
                259,594
                
                
                263,759**OPERATING
                    INCOME**
                
                
                32,158
                
                
                30,170**OTHER
                    INCOME (net of income taxes)**
                
                
                1,180
                
                
                736**NET
                    INTEREST CHARGES:**Interest
                    on
                    long-term debt
                
                
                6,934
                
                
                7,459Allowance
                    for
                    borrowed funds used during construction
                
                
                (347
                )
                
                (125
                )Other
                    interest
                    expense
                
                
                3,602
                
                
                2,188Net
                    interest
                    charges
                
                
                10,189
                
                
                9,522**NET
                    INCOME**
                
                
                23,149
                
                
                21,384**OTHER
                    COMPREHENSIVE INCOME:**Unrealized
                    gain on derivative hedges
                
                
                16
                
                
                16Unrealized
                    loss on available for sale securities
                
                
                (4
                )
                
                (3
                )Other
                    comprehensive income
                
                
                12
                
                
                13Income
                    tax
                    expense related to other comprehensive income
                
                
                6
                
                
                6Other
                    comprehensive income, net of tax
                
                
                6
                
                
                7**TOTAL
                    COMPREHENSIVE INCOME**
                
                $
                23,155
                
                $
                21,391The
                    preceding
                    Notes to Consolidated Financial Statements as they relate to
                    Pennsylvania
                    Electric Company arean
                    integral
                    part of these statements.
   142
  **PENNSYLVANIA
                      ELECTRIC COMPANY****CONSOLIDATED
                      BALANCE SHEETS****(Unaudited)**
 **March
                      31,**
                  
                  **December
                      31,****2006**
                  
                  **2005*****(In
                      thousands)*****ASSETS****UTILITY
                      PLANT:**In
                      service
                  
                  $
                  2,070,562
                  
                  $
                  2,043,885Less
                      -
                      Accumulated provision for depreciation
                  
                  
                  788,535
                  
                  
                  784,4941,282,027
                  
                  
                  1,259,391Construction
                      work in progress
                  
                  
                  33,332
                  
                  
                  30,8881,315,359
                  
                  
                  1,290,279**OTHER
                      PROPERTY AND INVESTMENTS:**Nuclear
                      plant
                      decommissioning trusts
                  
                  
                  115,534
                  
                  
                  113,368Non-utility
                      generation trusts
                  
                  
                  97,390
                  
                  
                  96,761Other
                  
                  
                  11,915
                  
                  
                  15,031224,839
                  
                  
                  225,160**CURRENT
                      ASSETS:**Cash
                      and cash
                      equivalents
                  
                  
                  35
                  
                  
                  35Receivables-Customers
                      (less accumulated provisions of $4,304,000 and $4,184,000,respectively,
                      for uncollectible accounts)
                  
                  
                  123,915
                  
                  
                  129,960Associated
                      companies
                  
                  
                  10,176
                  
                  
                  18,626Other
                  
                  
                  10,566
                  
                  
                  12,800Notes
                      receivable from associated companies
                  
                  
                  18,758
                  
                  
                  17,624Prepayments
                      and other
                  
                  
                  48,682
                  
                  
                  7,936212,132
                  
                  
                  186,981**DEFERRED
                      CHARGES AND OTHER ASSETS:**Goodwill
                  
                  
                  877,778
                  
                  
                  882,344Prepaid
                      pension costs
                  
                  
                  90,972
                  
                  
                  89,637Other
                  
                  
                  26,865
                  
                  
                  24,176995,615
                  
                  
                  996,157$
                  2,747,945
                  
                  $
                  2,698,577**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
                  
                  
                  1,197,999
                  
                  
                  1,202,551Accumulated
                      other comprehensive loss
                  
                  
                  (303
                  )
                  
                  (309
                  )Retained
                      earnings
                  
                  
                  48,973
                  
                  
                  25,823Total
                      common
                      stockholder's equity
                  
                  
                  1,352,481
                  
                  
                  1,333,877Long-term
                      debt
                      and other long-term obligations
                  
                  
                  476,704
                  
                  
                  476,5041,829,185
                  
                  
                  1,810,381**CURRENT
                      LIABILITIES:**Short-term
                      borrowings-Associated
                      companies
                  
                  
                  230,474
                  
                  
                  261,159Other
                  
                  
                  70,000
                  
                  
                  -Accounts
                      payable-Associated
                      companies
                  
                  
                  15,915
                  
                  
                  33,770Other
                  
                  
                  46,509
                  
                  
                  38,277Accrued
                      taxes
                  
                  
                  23,001
                  
                  
                  27,905Accrued
                      interest
                  
                  
                  14,306
                  
                  
                  8,905Other
                  
                  
                  17,329
                  
                  
                  19,756417,534
                  
                  
                  389,772**NONCURRENT
                      LIABILITIES:**Regulatory
                      liabilities
                  
                  
                  156,002
                  
                  
                  162,937Asset
                      retirement obligation
                  
                  
                  73,426
                  
                  
                  72,295Accumulated
                      deferred income taxes
                  
                  
                  113,419
                  
                  
                  106,871Retirement
                      benefits
                  
                  
                  104,022
                  
                  
                  102,046Other
                  
                  
                  54,357
                  
                  
                  54,275501,226
                  
                  
                  498,424**COMMITMENTS
                      AND CONTINGENCIES (Note 10)**$
                  2,747,945
                  
                  $
                  2,698,577The
                      preceding
                      Notes to Consolidated Financial Statements as they relate to
                      Pennsylvania
                      Electric Company are an integral part of thesebalance
                      sheets.
   143
 
  **PENNSYLVANIA
                        ELECTRIC COMPANY****CONSOLIDATED
                        STATEMENTS OF CASH
                        FLOWS****(Unaudited)****Three
                        Months Ended****March
                        31,****2006**
                    
                    **2005*****(In
                        thousands)*****CASH
                        FLOWS FROM OPERATING ACTIVITIES:**Net
                        income
                    
                    $
                    23,149
                    
                    $
                    21,384Adjustments
                        to
                        reconcile net income to net cash from operating
                        activities-Provision
                        for
                        depreciation
                    
                    
                    12,643
                    
                    
                    12,506Amortization
                        of regulatory assets
                    
                    
                    14,815
                    
                    
                    13,185Deferred
                        costs
                        recoverable as regulatory assets
                    
                    
                    (19,211
                    )
                    
                    (19,433
                    )Deferred
                        income taxes and investment tax credits, net
                    
                    
                    5,361
                    
                    
                    2,446Accrued
                        compensation and retirement benefits
                    
                    
                    (472
                    )
                    
                    (1,762
                    )Commodity
                        derivative transactions, net
                    
                    
                    (4,206
                    )
                    
                    -Decrease
                        (Increase) in operating assets:Receivables
                    
                    
                    16,729
                    
                    
                    39,145Prepayments
                        and other current assets
                    
                    
                    (36,540
                    )
                    
                    (35,119
                    )Increase
                        (Decrease) in operating liabilities:Accounts
                        payable
                    
                    
                    (9,623
                    )
                    
                    (24,234
                    )Accrued
                        taxes
                    
                    
                    (4,904
                    )
                    
                    10,205Accrued
                        interest
                    
                    
                    5,401
                    
                    
                    5,581Other
                    
                    
                    (6,745
                    )
                    
                    (217
                    )Net
                        cash
                        provided from (used for) operating activities
                    
                    
                    (3,603
                    )
                    
                    23,687**CASH
                        FLOWS FROM FINANCING ACTIVITIES:**New
                        Financing-Short-term
                        borrowings, net
                    
                    
                    39,315
                    
                    
                    -Redemptions
                        and Repayments-Long-term
                        debt
                    
                    
                    -
                    
                    
                    (13
                    )Short-term
                        borrowings, net
                    
                    
                    -
                    
                    
                    (1,803
                    )Dividend
                        Payments-Common
                        stock
                    
                    
                    -
                    
                    
                    (5,000
                    )Net
                        cash
                        provided from (used for) financing activities
                    
                    
                    39,315
                    
                    
                    (6,816
                    )**CASH
                        FLOWS FROM INVESTING ACTIVITIES:**Property
                        additions
                    
                    
                    (35,610
                    )
                    
                    (15,393
                    )Loans
                        to
                        associated companies, net
                    
                    
                    (1,134
                    )
                    
                    (3,082
                    )Proceeds
                        from
                        nuclear decommissioning trust fund sales
                    
                    
                    14,942
                    
                    
                    7,778Investments
                        in
                        nuclear decommissioning trust funds
                    
                    
                    (14,942
                    )
                    
                    (7,778
                    )Other,
                        net
                    
                    
                    1,032
                    
                    
                    1,603Net
                        cash used
                        for investing activities
                    
                    
                    (35,712
                    )
                    
                    (16,872
                    )Net
                        change in
                        cash and cash equivalents
                    
                    
                    -
                    
                    
                    (1
                    )Cash
                        and cash
                        equivalents at beginning of period
                    
                    
                    35
                    
                    
                    36Cash
                        and cash
                        equivalents at end of period
                    
                    $
                    35
                    
                    $
                    35The
                        preceding
                        Notes to Consolidated Financial Statements as they relate
                        to Pennsylvania
                        Electric Company are anintegral
                        part
                        of these
                        statements.
 
  144
 
 ***Report
        of Independent Registered Public Accounting Firm***
 
 
 
 
 
 
 
 
 
 To
        the Stockholder
        and Board of
 Directors
        of
        Pennsylvania Electric Company:
 
 We
        have reviewed the
        accompanying consolidated balance sheet of Pennsylvania Electric Company
        and its
        subsidiaries as of March 31, 2006 and the related consolidated statements
        of income, comprehensive income and cash flows for each of the three-month
        periods ended March 31, 2006 and 2005. These interim financial statements
        are
        the responsibility of the Company’s management.
 
 We
        conducted our
        review in accordance with the standards of the Public Company Accounting
        Oversight Board (United States). A review of interim financial information
        consists principally of applying analytical procedures and making inquiries
        of
        persons responsible for financial and accounting matters. It is substantially
        less in scope than an audit conducted in accordance with the standards of
        the
        Public Company Accounting Oversight Board, the objective of which is the
        expression of an opinion regarding the financial statements taken as a whole.
        Accordingly, we do not express such an opinion.
 
 Based
        on our review,
        we are not aware of any material modifications that should be made to the
        accompanying consolidated interim financial statements for them to be in
        conformity with accounting principles generally accepted in the United States
        of
        America.
 
 We
        previously
        audited, in accordance with the standards of the Public Company Accounting
        Oversight Board (United States), the consolidated balance sheet as of December
        31, 2005, and the related consolidated statements of income, capitalization,
        common stockholder’s equity, preferred stock, cash flows and taxes for the year
        then ended (not presented herein), and in our report (which contained references
        to the Company’s change in its method of accounting for asset retirement
        obligations as of January 1, 2003 and conditional asset retirement obligations
        as of December 31, 2005 as discussed in Note 2(G) and Note 9 to those
        consolidated financial statements) dated February 27, 2006, we expressed an
        unqualified opinion on those consolidated financial statements. In our opinion,
        the information set forth in the accompanying consolidated balance sheet
        as of
        December 31, 2005, is fairly stated in all material respects in relation
        to the
        consolidated balance sheet from which it has been derived.
 
 
 
 
 PricewaterhouseCoopers
        LLP
 Cleveland,
        Ohio
 May
        8,
        2006
 
 
 
  145
  
 **PENNSYLVANIA
        ELECTRIC COMPANY**
 
 **MANAGEMENT’S
        DISCUSSION AND** **** **ANALYSIS
        OF**
 **RESULTS
        OF
        OPERATIONS** **** **AND
        FINANCIAL CONDITION**
 
 
 Penelec is a wholly owned electric utility subsidiary of FirstEnergy. Penelec
        conducts business in northern, western and south central Pennsylvania, providing
        regulated transmission and distribution services. Penelec also provides
        generation services to those customers electing to retain Penelec as their
        power
        supplier.
 
 **Results
        of Operations**
  Net income in the first quarter of 2006 increased to $23 million, compared
        to
        $21 million in the first quarter of 2005. The increase resulted from lower
        other operating costs, partially offset by lower operating revenues and higher
        purchased power costs.
 
 Operating revenues decreased by $2 million in the first quarter of 2006 compared
        to the first quarter of 2005, primarily due to lower transmission and
        distribution revenues partially offset by higher retail generation revenues.
        T ransmission
        revenues
        decreased by $12 million due to lower transmission load requirements and
        lower
        prices. The decreased loads (and related lower congestion revenues) reflect
        milder temperatures in 2006 compared with 2005, as demonstrated by a 14.6%
        decrease in heating degree days, and which also resulted in lower transmission
        expenses discussed further below. Distribution revenues decreased by
        $2 million due to a 2.6% decrease in KWH deliveries reflecting the effect
        of the unseasonably mild weather, partially offset by slightly higher composite
        unit prices.
 
 Retail generation revenues increased by $11 million primarily due to a 15.1%
        increase in industrial KWH sales and higher composite unit prices that resulted
        in increased revenues in all customer sectors (residential - $2 million;
        commercial - $2 million; and industrial - $7 million). The industrial sales
        volume increased primarily from reduced generation service provided by
        alternative suppliers, which decreased by 14.3 percentage points in the first
        quarter of 2006. In
        addition, other
        operating revenues increased by $1 million due to a higher payment received
        in the first quarter of 2006 under a contract provision associated with the
        prior sale of TMI Unit 1. Under the contract, additional payments are
        received if subsequent energy prices rise above specified levels, which
        occurred. This payment is credited to Penelec’s customers, resulting in no net
        earnings effect.
 
 Changes in KWH sales by customer class in the first quarter of 2006 compared
        to
        the same period of 2005 are summarized in the following table:
 
 **Changes
                  in KWH Sales****Increase
                  (Decrease)**Retail
                  Electric Generation:Residential
              
              
              (2.2
              )%Commercial
              
              
              (1.4
              )%Industrial
              
              
              15.1
              %**Total
                  Retail Electric Generation Sales**
              
              
              2.8
              %Distribution
                  Deliveries:Residential
              
              
              (2.4
              )%Commercial
              
              
              (2.5
              )%Industrial
              
              
              (3.1
              )%**Total
                  Distribution Deliveries**
              
              
              (2.6
              )%
 
  146
 
 *Operating
        Expenses and Taxes*
 
 Total
        operating expenses and taxes decreased by $4 million in the first quarter
        of
        2006 compared to the first quarter of 2005. The following table presents
        changes
        from the prior year by expense category:
 
 **Operating
                  Expenses and Taxes - Changes (In millions)****Increase
                  (Decrease)**Purchased
                  power costs
              
              $
              11Other
                  operating costs
              
              
              (15
              )Provision
                  for
                  depreciation
              
              
              -Amortization
                  of regulatory assets
              
              
              2General
                  taxes
              
              
              1Income
                  taxes
              
              
              (3
              )**Total
                  operating expenses and taxes**
              
              $
              (4
              )
  Purchased power costs increased by $11 million or 7.6% in the first quarter
        of
        2006, compared to the first quarter of 2005. The increase is primarily
        attributable to higher unit costs from non-affiliated suppliers and increased
        KWH purchased to meet increased retail generation sales requirements. Other
        operating costs decreased due to lower transmission expenses resulting from
        lower congestion charges and to higher levels of construction activities
        in the
        first quarter of 2006 compared to a higher level of maintenance activities
        in
        the same period of 2005 for energy delivery operations and reliability
        initiatives. Amortization of regulatory assets increased due to increases
        in CTC
        revenue recovery compared to the first quarter of 2005.
 
 General taxes increased $1 million due to the higher Pennsylvania gross receipts
        taxes in the first quarter of 2006 compared to the same period in 2005. Income
        taxes decreased $3 million due to lower pre-tax income in the first quarter
        of
        2006 compared to the first quarter of 2005.
 
 **Capital
        Resources and Liquidity**
 
 Penelec’s cash requirements in 2006 for operating expenses, construction
        expenditures and scheduled debt maturities, are expected to be met by a
        combination of cash from operations and short-term credit arrangements.
 
 *Changes
        in Cash
        Position*
 
 As of March 31, 2006 and December 31, 2005, Penelec had $35,000 of cash and
        cash equivalents.
 
 *Cash
        Flows From
        Operating Activities*
 
 Net cash used for operating activities was $4 million in the first quarter
        of
        2006, compared to net cash provided from operating activities of $24 million
        in
        the first quarter of 2005, summarized as follows:
 
 **Three
                  Months Ended****March
                  31,****Operating
                  Cash Flows**
              
              
              **2006**
              
              **2005*****(In
                  millions)***Cash
                  earnings(1)
              
              
              $
              32
              
              $
              28Working
                  capital and other
              
              
              
              (36
              )
              
              (4
              )**Net
                  cash provided from (used for) Operating
                  Activities**
              
              
              **$**
              **(4**
              **)**
              **$**
              **24**
 
 (1) Cash
        earnings is a non-GAAP measure (see reconciliation below).
 
 Cash earnings (in the table above) are not a measure of performance calculated
        in accordance with GAAP. Penelec believes that cash earnings are a useful
        financial measure because it provides investors and management with an
        additional means of evaluating its cash-based operating
        performance.
 
  147
  
 **Three
                  Months Ended****March
                  31,****Reconciliation
                  of Cash Earnings**
              
              **2006**
              
              **2005*****(In
                  millions)***Net
                  Income
                  (GAAP)
              
              $
              23
              
              $
              21Non-Cash
                  Charges (Credits):Provision
                  for
                  depreciation
              
              
              13
              
              
              13Amortization
                  of regulatory assets
              
              
              15
              
              
              13Deferred
                  costs
                  recoverable as regulatory assets
              
              
              (19
              )
              
              (19
              )Deferred
                  income taxes and investment tax credits
              
              
              5
              
              
              2Commodity
                  derivative transactions, net
              
              
              (4
              )
              
              -Other
                  non-cash
                  expenses
              
              
              (1
              )
              
              (2
              )Cash
                  earnings
                  (Non-GAAP)
              
              $
              32
              
              $
              28
 
 The $4 million increase in cash earnings is described above under “Results of
        Operations.” The $32 million decrease in working capital primarily resulted
        from a decrease of $22 million in cash provided from the settlement of
        receivables and decreases of $15 million in accrued taxes and $2 million in
        accrued liabilities for consumer education, partially offset by a decrease
        of
        $14 million in accounts payable.
 
 *Cash
        Flows From
        Financing Activities*
 
 Net cash provided from financing activities was $39 million in the first
        quarter
        of 2006 compared to net cash used for financing activities of $7 million in
        the first quarter of 2005. The change reflects a $41 million increase in
        short-term borrowings and a $5 million reduction in common stock dividend
        payments to FirstEnergy in the first quarter of 2006.
 
 Penelec had approximately $19 million of cash and temporary investments (which
        includes short-term notes receivable from associated companies) and
        approximately $300 million of short-term indebtedness as of March 31, 2006.
        Penelec has authorization from the SEC, continued by FERC rules adopted as
        a
        result of EPACT's repeal of PUHCA, to incur short-term debt of up to $250
        million and authorization from the PPUC to incur money pool borrowings of
        up to
        $300 million. In addition, Penelec has $75 million of available
        accounts receivable financing facilities as of March 31, 2006 from Penelec
        Funding, Penelec's wholly owned subsidiary. As a separate legal entity with
        separate creditors, Penelec Funding would have to satisfy its obligations
        to
        creditors before any of its remaining assets could be made available to Penelec.
        As of March 31, 2006 the facility was drawn for
        $70 million.
 
 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 March 31, 2006,
        Penelec had the ability to issue $39 million of additional senior notes
        based upon FMB collateral. Penelec has no restrictions on the issuance of
        preferred stock.
 
 Penelec ,
        FirstEnergy, OE,
        Penn, CEI, TE, JCP&L, Met-Ed, FES and ATSI, as Borrowers, have entered into
        a syndicated $2 billion five-year revolving credit facility which expires
        in June 2010. 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.
 
 Under the revolving credit facility, borrowers may request the issuance of
        LOCs
        expiring up to one year from the date of issuance. The stated amount of
        outstanding LOCs will count against total commitments available under the
        facility and against the applicable borrower’s borrowing sub-limit. Total unused
        borrowing capability under existing credit facilities and accounts receivable
        financing facilities totaled $255 million.
 
 The revolving credit facility contains financial covenants requiring each
        borrower to maintain a consolidated debt to total capitalization ratio of
        no
        more than 65%. As of March 31, 2006, Penelec’s debt to total capitalization
        as defined under the revolving credit facility was 36%.
 
 The
        facility does not contain any provisions that either restrict Penelec's ability
        to borrow or accelerate repayment of outstanding advances as a result of
        any
        change in its credit ratings. Pricing is defined in “pricing grids”, whereby the
        cost of funds borrowed under the facility is related to Penelec's credit
        ratings.
 
 Penelec has the ability to borrow from its regulated affiliates and FirstEnergy
        to meet its short-term working capital requirements. FESC administers this
        money
        pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries.
        Companies receiving a loan under the money pool agreements must repay the
        principal, together with accrued interest, within 364 days of borrowing the
        funds. The rate of interest is the same for each company receiving a loan
        from
        the pool and is based on the average cost of funds available through the
        pool.
        The average interest rate for borrowings under these arrangements in the
        first
        quarter of 2006 was 4.58%.
  148
 
 Penelec’s access to capital markets and costs of financing are dependent on the
        ratings of its securities and that of FirstEnergy. The ratings outlook from
        S&P on all securities is stable. The ratings outlook from Moody's and Fitch
        on all securities is positive.
 
 *Cash
        Flows From
        Investing Activities*
  During the remaining three quarters of 2006, capital requirements for property
        additions are expected to be about $66 million. Penelec’s capital spending
        for the period 2006-2010 is expected to be about $489 million, of which
        approximately $103 million applies to 2006. The capital spending is
        primarily for property additions supporting the distribution of
        electricity.
 
 **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 oversight to risk management activities throughout the
        Company.
 
 *Commodity
        Price
        Risk*
 
 Penelec is exposed to market risk primarily due to fluctuations in electricity,
        energy transmission, natural gas, coal, and emission prices. To manage the
        volatility relating to these exposures, Penelec uses a variety of non-derivative
        and derivative instruments, including forward contracts, options, futures
        contracts and swaps. The derivatives are used principally for hedging purposes.
        All derivatives that fall within the scope of SFAS 133 must be recorded at
        their fair value and marked to market. The majority of Penelec’s derivative
        hedging contracts qualify for the normal purchase and normal sale exception
        under SFAS 133. Contracts that are not exempt from such treatment include
        purchase power agreements with NUG entities that were structured pursuant
        to the
        Public Utility Regulatory Policy Act of 1978. These non-trading contracts
        are
        adjusted to fair value at the end of each quarter, with a corresponding
        regulatory asset recognized for above-market costs. The
        change in the
        fair value of commodity derivative contracts related to energy production
        during
        the first quarter 2006 is summarized in the following table:
 
 **Three
                  Months Ended****March 31,
                  2006****Increase
                  (Decrease) in the Fair Value of Derivative
                  Contracts**
              
              **Non-Hedge**
              
              **Hedge**
              
              **Total*****(In
                  millions)***Change
                  in the
                  fair value of commodity derivative contractsOutstanding
                  net asset at beginning of period
              
              $
              27
              
              $
              -
              
              $
              27New
                  contract
                  value when entered
              
              
              -
              
              
              -
              
              
              -Additions/Changes
                  in value of existing contracts
              
              
              3
              
              
              -
              
              
              3Change
                  in
                  techniques/assumptions
              
              
              -
              
              
              -
              
              
              -Settled
                  contracts
              
              
              -
              
              
              -
              
              
              -**Net
                  Assets - Derivatives Contracts as of March 31,
                  2006**(1)
              
              **$**
              **30**
              
              **$**
              **-**
              
              **$**
              **30****Impact
                  of Changes in Commodity Derivative
                  Contracts**(2)Income
                  Statement Effects (Pre-Tax)
              
              $
              6
              
              $
              -
              
              $
              6Balance
                  Sheet
                  Effects:OCI
                  (Pre-Tax)
              
              $
              -
              
              $
              -
              
              $
              -Regulatory
                  Asset (net)
              
              $
              3
              
              $
              -
              
              $
              3
 
 (1)
              Includes
                  $11 million in non-hedge commodity derivative contracts, which are
                  offset by a regulatory liability.
 (2)
              Represents
                  the
                  decrease in value of existing contracts, settled contracts and
                  changes in
                  techniques/ assumptions.
  149
 
 Derivatives
        are
        included on the Consolidated Balance Sheet as of March 31, 2006 as
        follows:
 
 **Non-Hedge**
              
              **Hedge**
              
              **Total*****(In
                  millions)*****Current-**Other
                  assets
              
              $
              4
              
              $
              -
              
              $
              4Other
                  liabilities
              
              
              -
              
              
              -
              
              
              -**Non-Current-**Other
                  deferred
                  charges
              
              
              26
              
              
              -
              
              
              26Other
                  noncurrent liabilities
              
              
              -
              
              
              -
              
              
              -**Net
                  assets**
              
              **$**
              **30**
              
              $
              -
              
              $
              30
 
 The valuation of derivative contracts is based on observable market information
        to the extent that such information is available. In cases where such
        information is not available, Penelec relies on model-based information.
        The
        model provides estimates of future regional prices for electricity and an
        estimate of related price volatility. Penelec uses these results to develop
        estimates of fair value for financial reporting purposes and for internal
        management decision making. Sources of information for the valuation of
        commodity derivative contracts as of March 31, 2006 are summarized by year
        in the following table:
 
 **Source
                  of Information****Fair
                  Value by Contract Year**
              
              **2006**(1)
              
              **2007**
              
              **2008**
              
              **2009**
              
              **2010**
              
              **Thereafter**
              
              **Total*****(In
                  millions)***Other
                  external
                  sources (2)
              
              $
              (14
              )
              $
              (3
              )
              $
              2
              
              $
              -
              
              $
              -
              
              $
              -
              
              $
              (15
              )Prices
                  based
                  on models
              
              
              -
              
              
              -
              
              
              -
              
              
              5
              
              
              3
              
              
              37
              
              
              45**Total**(3)
              
              **$**
              **(14**
              **)**
              **$**
              **(3**
              **)**
              **$**
              **2**
              
              **$**
              **5**
              
              **$**
              **3**
              
              **$**
              **37**
              
              **$**
              **30**
 
 (1) For
        the last three quarters of 2006.
 (2) Broker
        quote sheets.
 (3) Includes
        $11 million from an embedded option that is offset by a regulatory liability
        and
        does not affect earnings.
 
 Penelec performs
        sensitivity
        analyses to estimate its exposure to the market risk of its commodity positions.
        A hypothetical 10% adverse shift in quoted market prices in the near term
        on
        both of Penelec's trading and non-trading derivative instruments would not
        have
        had a material effect on its consolidated financial position or cash flows
        as of
        March 31, 2006. Penelec estimates that if energy commodity prices
        experienced an adverse 10% change, net income for the next 12 months would
        not change, as the prices for all commodity positions are already above the
        contract price caps.
 
 *Equity
        Price
        Risk*
  Included in nuclear decommissioning trusts are marketable equity securities
        carried at their current fair value of approximately $65 million and $62
        million as of March 31, 2006 and December 31, 2005, respectively. A
        hypothetical 10% decrease in prices quoted by stock exchanges would result
        in a
        $7 million reduction in fair value as of March 31, 2006.
 
 **Regulatory
        Matters**
 
 Regulatory assets and liabilities are costs which have been authorized by
        the
        PPUC and the FERC for recovery from or credit to customers in future periods
        and, without such authorization, would have been charged or credited to income
        when incurred. Penelec’s net regulatory liabilities were approximately
        $156 million and $163 million as of March 31, 2006 and
        December 31, 2005, respectively, and are included under Noncurrent
        Liabilities on the Consolidated Balance Sheets.
 
 Met-Ed’s
        and
        Penelec’s combined portion of total merger savings during 2001 - 2004 is
        estimated to be approximately $51 million. A procedural schedule was
        established by the ALJ on January 17, 2006. Met-Ed and Penelec filed
        initial testimony on March 1, 2006. Hearings are currently scheduled for
        the end of October 2006 with the ALJ’s recommended decision to be issued in
        February 2007. Met-Ed and Penelec have requested that this proceeding be
        consolidated with the April 10, 2006 transition plan filing proceeding as
        discussed below. Penelec is unable to predict the outcome of this
        proceeding.
  150
 
 In
        an
        October 16, 2003 order, the PPUC approved September 30, 2004 as the
        date for Met-Ed's and Penelec's NUG trust fund refunds. The PPUC order also
        denied their accounting treatment request regarding the CTC rate/shopping
        credit
        swap by requiring Met-Ed and Penelec to treat the stipulated CTC rates that
        were
        in effect from January 1, 2002 on a retroactive basis. On October 22,
        2003, Met-Ed and Penelec filed an Objection with the Commonwealth Court asking
        that the Court reverse this PPUC finding; a Commonwealth Court judge
        subsequently denied their Objection on October 27, 2003 without
        explanation. On October 31, 2003, Met-Ed and Penelec filed an Application
        for Clarification of the Court order with the Commonwealth Court, a Petition
        for
        Review of the PPUC's October 2 and October 16, 2003 Orders, and an
        Application for Reargument, if the judge, in his clarification order, indicates
        that Met-Ed's and Penelec's Objection was intended to be denied on the merits.
        The Reargument Brief before the Commonwealth Court was filed on January 28,
        2005. Oral arguments are scheduled for June 8, 2006.
 
 On
        November 18,
        2004, the FERC issued an order eliminating the regional through and out rates
        (RTOR) for transmission service between the MISO and PJM regions. The FERC
        also
        ordered the MISO, PJM and the transmission owners within the MISO and PJM
        to
        submit compliance filings containing a mechanism - the Seams Elimination
        Cost
        Adjustment (SECA) -- to recover lost RTOR revenues during a 16-month transition
        period from load serving entities. The FERC issued orders in 2005 setting
        the
        SECA for hearing. ATSI, JCP&L, Met-Ed, Penelec, and FES continue to be
        involved in the FERC hearings concerning the calculation and imposition of
        the
        SECA charges. The hearing began on May 1, 2006. The FERC has ordered the
        Presiding Judge to issue an initial decision by August 11,
        2006.
  On
        January 31,
        2005, certain PJM transmission owners made three filings with the FERC pursuant
        to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and
        Penelec were parties to that proceeding and joined in two of the filings.
        In the
        first filing, the settling transmission owners submitted a filing justifying
        continuation of their existing rate design within the PJM RTO. In the second
        filing, the settling transmission owners proposed a revised Schedule 12 to
        the PJM tariff designed to harmonize the rate treatment of new and existing
        transmission facilities. Interventions and protests were filed on
        February 22, 2005. In the third filing, Baltimore Gas and Electric Company
        and Pepco Holdings, Inc. requested a formula rate for transmission service
        provided within their respective zones. On May 31, 2005, the FERC issued an
        order on these cases. First, it set for hearing the existing rate design
        and
        indicated that it will issue a final order within six months. American
        Electric
        Power Company, Inc. filed in opposition proposing to create a "postage stamp"
        rate for high voltage transmission facilities across PJM. Second, the FERC
        approved the proposed Schedule 12 rate harmonization. Third, the FERC accepted
        the proposed formula rate, subject to referral and hearing procedures. On
        June 30, 2005, the settling PJM transmission owners filed a request for
        rehearing of the May 31, 2005 order. On
        March 20, 2006 a settlement was filed with FERC in the formula rate
        proceeding that generally accepts the companies' formula rate proposal. The
        FERC
        issued an order approving this settlement on April 19, 2006. If the FERC
        accepts AEP's proposal, significant additional transmission revenues would
        be
        imposed on JCP&L, Met-Ed, Penelec, and other transmission zones within
        PJM.
 
 As
        of March 31,
        2006, Met-Ed's and Penelec's regulatory deferrals pursuant to the 1998
        Restructuring Settlement (including the Phase 2 Proceedings) and the
        FirstEnergy/GPU Merger Settlement Stipulation are $328 million and
        $50 million, respectively. Penelec's $50 million is subject to the pending
        resolution of taxable income issues associated with NUG trust fund proceeds.
 
 On
        January 12, 2005,
        Penelec filed, before the PPUC, a request for deferral of transmission-related
        costs beginning January 1, 2005. The OCA, OSBA, OTS, MEIUG, PICA, Allegheny
        Electric Cooperative and Pennsylvania Rural Electric Association have all
        intervened in the case. As of March 31, 2006, the PPUC had taken no action
        on
        the request and Penelec had not yet implemented deferral accounting for these
        costs. Penelec sought to consolidate this proceeding (and modified its request
        to provide deferral of 2006 transmission-related costs only) with the
        comprehensive rate filing it made on April 10, 2006 as described below. On
        May 4, 2006, the PPUC approved the modified request. Accordingly, Penelec
        will
        implement deferral accounting for these costs in the second quarter of 2006,
        which will include $4 million representing the amount that was
        incurred in the first quarter of 2006 -- the deferral of such amount will
        be reflected in the second quarter of 2006.
 
 Met-Ed
        and Penelec
        purchase a portion of their PLR requirements from FES through a wholesale
        power
        sales agreement. Under this agreement, FES retains the supply obligation
        and the
        supply profit and loss risk for the portion of power supply requirements
        not
        self-supplied by Met-Ed and Penelec under their contracts with NUGs and other
        unaffiliated suppliers. The FES arrangement reduces Met-Ed's and Penelec's
        exposure to high wholesale power prices by providing power at a fixed price
        for
        their uncommitted PLR energy costs during the term of the agreement with
        FES.
        The wholesale power sales agreement with FES could automatically be extended
        for
        each successive calendar year unless any party elects to cancel the agreement
        by
        November 1 of the preceding year. On November 1, 2005, FES and the other
        parties thereto amended the agreement to provide FES the right in 2006 to
        terminate the agreement at any time upon 60 days notice. On April 7, 2006,
        the parties to the wholesale power sales agreement entered into a Tolling
        Agreement that arises out of FES’ notice to Met-Ed and Penelec that FES elected
        to exercise its right to terminate the wholesale power sales agreement effective
        midnight December 31, 2006, because that agreement is not economically
        sustainable to FES.
  151
 
 In
        lieu of allowing
        such termination to become effective as of December 31, 2006, the parties
        agreed, pursuant to the Tolling Agreement, to amend the wholesale power sales
        agreement to provide as follows:
 
 1.  The
        termination
        provisions of the wholesale power sales agreement will be tolled for one
        year
        until December 31, 2007, provided that during such tolling period:
 
 a.
            FES
                will be
                permitted to terminate the wholesale power sales agreement at any
                time
                with sixty days written notice; b.
            Met-Ed
                and
                Penelec will procure through arrangements other than the wholesale
                power
                sales agreement beginning December 1, 2006 and ending December 31,
                2007,
                approximately 33% of the amounts of capacity and energy necessary
                to
                satisfy their PLR obligations for which Committed Resources (i.e.,
                non-utility generation under contract to Met-Ed and Penelec, Met-Ed-
                and
                Penelec-owned generating facilities, purchased power contracts and
                distributed generation) have not been obtained;
                and c.
            FES
                will not
                be obligated to supply additional quantities of capacity and energy
                in the
                event that a supplier of Committed Resources defaults on its supply
                agreement. 
 2.  During
        the tolling
        period FES will not act as agent for Met-Ed or Penelec in procuring the services
        under section 1.(b) above; and
 
 3.  The
        pricing
        provision of the wholesale power sales agreement shall remain unchanged provided
        Met-Ed and Penelec comply with the provisions of the Tolling Agreement and
        any
        applicable provision of the wholesale power sales agreement.
 
 In
        the event that
        FES elects not to terminate the wholesale power sales agreement effective
        midnight December 31, 2007, similar tolling agreements effective after
        December 31, 2007 are expected to be considered by FES for subsequent years
        if
        Met-Ed and Penelec procure through arrangements other than the wholesale
        power
        sales agreement approximately 64%, 83% and 95% of the additional amounts
        of
        capacity and energy necessary to satisfy their PLR obligations for 2008,
        2009
        and 2010, respectively, for which Committed Resources have not been obtained
        from the market.
 
 The
        wholesale power
        sales agreement, as modified by the Tolling Agreement, requires Met-Ed and
        Penelec to satisfy the portion of their PLR obligations currently supplied
        by
        FES from unaffiliated suppliers at prevailing prices, which are likely to
        be
        higher than the current price charged by FES under the current agreement
        and, as
        a result, Met-Ed’s and Penelec’s purchased power costs could materially
        increase. If Met-Ed and Penelec were to replace the entire FES supply at
        current
        market power prices without corresponding regulatory authorization to increase
        their generation prices to customers, each company would likely incur a
        significant increase in operating expenses and experience a material
        deterioration in credit quality metrics. Under such a scenario, each company's
        credit profile would no longer be expected to support an investment grade
        rating
        for its fixed income securities. There can be no assurance, however, that
        if FES
        ultimately determines to terminate, or significantly modify the agreement,
        timely regulatory relief will be granted by the PPUC pursuant to the April
        10,
        2006 comprehensive rate filing discussed below, or, to the extent granted,
        adequate to mitigate such adverse consequences.
 
 Met-Ed
        and Penelec
        made a comprehensive rate filing with the PPUC on April 10, 2006 that
        addresses a number of transmission, distribution and supply issues. If Met-Ed's
        and Penelec's preferred approach involving accounting deferrals is approved,
        the
        filing would increase annual revenues by $216 million and $157 million,
        respectively. That filing includes, among other things, a request to charge
        customers for an increasing amount of market priced power procured through
        a
        competitive bid process as the amount of supply provided under the existing
        FES
        agreement is phased out in accordance with the April 7, 2006 Tolling agreement
        described above. Met-Ed
        and Penelec
        also requested approval of the January 12, 2005 petition for the deferral
        of
        transmission-related costs discussed above, but only for those costs incurred
        during 2006. In this rate filing, Met-Ed and Penelec also requested recovery
        of
        annual transmission and related costs incurred on or after January 1, 2007,
        plus the amortized portion of 2006 costs over a ten-year period, along with
        applicable carrying charges, through an adjustable rider similar to that
        implemented in Ohio. Changes in the
        recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs
        are
        also included in the filing. The filing contemplates a reduction in distribution
        rates for Met-Ed in the amount of $37 million annually and an increase in
        distribution rates for Penelec in the amount of $20 million annually. Although
        the companies have proposed an effective date of June 10, 2006, it is
        expected that the PPUC will suspend the effective date for seven months as
        permitted under Pennsylvania law. Hearings are expected to be scheduled for
        the
        second half of 2006 and a PPUC decision is expected early in the first quarter
        of 2007.
 
 See
        Note 11 to the
        consolidated financial statements for further details and a complete discussion
        of regulatory matters in Pennsylvania, including a more detailed discussion
        of
        reliability initiatives, including actions by the PPUC that impact
        Penelec.
  152
 
 **Environmental
        Matters**
 
 Penelec accrues environmental liabilities when it concludes that it is probable
        that it has an obligation for such costs and can reasonably determine the
        amount
        of such costs. Unasserted claims are reflected in Penelec's determination
        of
        environmental liabilities and are accrued in the period that they are both
        probable and reasonably estimable.
 
 Penelec has been named a PRP at waste disposal sites, which may require cleanup
        under the Comprehensive Environmental Response, Compensation and Liability
        Act
        of 1980. Allegations of disposal of hazardous substances at historical sites
        and
        the liability involved are often unsubstantiated and subject to dispute;
        however, federal law provides that all PRPs for a particular site are liable
        on
        a joint and several basis.
 
 **Other
        Legal Proceedings**
 
 There are various lawsuits, claims (including claims for asbestos exposure)
        and
        proceedings related to Penelec’s normal business operations pending against
        Penelec. The other material items not otherwise discussed below are described
        in
        Note 10(C) to the consolidated financial statements.
 
 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
        March 31, 2006 for any expenditure 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 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 has been filed. FirstEnergy was also named, along
        with
        several other entities, in a complaint in New Jersey State Court. The
        allegations against FirstEnergy are based, in part, on an alleged failure
        to
        protect the citizens of Jersey City from an electrical power outage. No
        FirstEnergy entity serves any customers in Jersey City. A responsive pleading
        has been filed. On
        April 28, 2006,
        the Court granted FirstEnergy's motion to dismiss. It is uncertain whether
        the
        plaintiff will appeal. No
        estimate of
        potential liability has been undertaken in either of these matters.
 
 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 and results of operations.
  153
 
 **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. This EITF issue will not have a material impact on
        Penelec's financial results.
 
 *SFAS
        155 -
“Accounting for Certain Hybrid Financial Instruments-an amendment of FASB
        Statements No. 133 and 140”*
  In February 2006, the FASB issued SFAS 155 which amends SFAS 133 “Accounting for
        Derivative Instruments and Hedging Activities,” (SFAS 133) and SFAS 140
“Accounting for Transfers and Servicing of Financial Assets and Extinguishments
        of Liabilities.” This Statement permits fair value remeasurement for any hybrid
        financial instrument that contains an embedded derivative that otherwise
        would
        require bifurcation, clarifies which interest-only strips and principal-only
        strips are not subject to the requirements of SFAS 133, establishes a
        requirement to evaluate interests in securitized financial assets to identify
        interests that are freestanding derivatives or that are hybrid financial
        instruments that contain an embedded derivative requiring bifurcation, clarifies
        that concentrations of credit risk in the form of subordination are not embedded
        derivatives and amends SFAS 140 to eliminate the prohibition on a qualifying
        special-purpose entity from holding a derivative financial instrument that
        pertains to a beneficial interest other than another derivative instrument.
        This
        Statement is effective for all financial instruments acquired or issued
        beginning January 1, 2007. Penelec is currently evaluating the impact of
        this Statement on its financial statements.
   154
 
 **ITEM
        3.
        QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
        RISK**
 
 See “Management’s Discussion and Analysis of Results of Operation and Financial
        Condition - Market Risk Information” in Item 2 above.
 
 **ITEM
        4.
        CONTROLS AND PROCEDURES**
 
 **(a)**  **EVALUATION
        OF DISCLOSURE CONTROLS AND PROCEDURES**
  The applicable registrant's chief executive officer and chief financial officer
        have reviewed and evaluated the registrant's disclosure controls and procedures.
        The term disclosure controls and procedures means controls and other procedures
        of a registrant that are designed to ensure that information required to
        be
        disclosed by the registrant in the reports that it files or submits under
        the
        Securities Exchange Act of 1934 (15 U.S.C. 78a et seq.) is recorded, processed,
        summarized and reported, within the time periods specified in the Securities
        and
        Exchange Commission's rules and forms. Disclosure controls and procedures
        include, without limitation, controls and procedures designed to ensure that
        information required to be disclosed by an issuer in the reports that it
        files
        or submits under that Act is accumulated and communicated to the registrant's
        management, including its principal executive and principal financial officers,
        or persons performing similar functions, as appropriate to allow timely
        decisions regarding required disclosure. Based on that evaluation, those
        officers have concluded that the applicable registrant's disclosure controls
        and
        procedures are effective and were designed to bring to their attention material
        information relating to the registrant and its consolidated subsidiaries
        by
        others within those entities.
 
 **(b)**  **CHANGES
        IN
        INTERNAL CONTROLS**
  During the quarter ended March 31, 2006, 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.
 
  155
  
 ***PART
        II. OTHER INFORMATION***
 
 **ITEM
        1.**  **LEGAL
        PROCEEDINGS**
 
 Information required for Part II, Item 1 is incorporated by reference to
        the
        discussions in Notes 10 and 11 of the Consolidated Financial Statements in
        Part
        I, Item 1 of this Form 10-Q.
  **ITEM
        1A.**  **RISK
        FACTORS**
 
 Not Applicable.
 
 **ITEM
        2.**  **UNREGISTERED
        SALES OF EQUITY SECURITIES AND USE OF PROCEEDS**
 
 **(c)**  **FirstEnergy**
 
 The table below includes information on a monthly basis regarding purchases
        made
        by FirstEnergy of its common stock.
 
 **Period****January
                  1-31,**
              
              **February
                  1-28,**
              
              **March
                  1-31,**
              
              **First****2006**
              
              **2006**
              
              **2006**
              
              **Quarter**Total
                  Number
                  of Shares Purchased (a)
              
              150,321
              
              143,522
              
              769,145
              
              1,062,988Average
                  Price
                  Paid per Share
              
              $50.77
              
              $50.67
              
              $50.84
              
              $50.81Total
                  Number
                  of Shares PurchasedAs
                  Part of
                  Publicly Announced Plansor
                  Programs (b)
              
              
              -
              
              
              -
              
              
              -
              
              
              -Maximum
                  Number
                  (or Approximate DollarValue)
                  of
                  Shares that May Yet BePurchased
                  Under the Plans or Programs
              
              
              -
              
              
              -
              
              
              -
              
              
              -
  (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
        6.**  **EXHIBITS**
 
 
 **Exhibit**
                **Number****FirstEnergy**10.1*
              Form
                  of
                  Guaranty Agreement dated as of April 3, 2006 by FirstEnergy Corp.
                  in favor
                  of the Participating Banks, Barclays Bank PLC, as administrative
                  agent and
                  fronting bank, and KeyBank National Association, as syndication
                  agent,
                  under the related Letter of Credit and Reimbursement
                  Agreement.10.2*
              Form
                  of Letter
                  of Credit and Reimbursement Agreement dated as of April 3, 2006
                  among
                  FirstEnergy Generation Corp., the Participating Banks, Barclays
                  Bank PLC,
                  as administrative agent and fronting bank, and KeyBank National
                  Association, as syndication agent.10.3*
              Form
                  of Trust
                  Indenture dated as of April 1, 2006 between the Ohio Water Development
                  Authority and The Bank of New York Trust Company, N.A. as Trustee
                  securing
                  pollution control revenue refunding bonds issued on behalf of FirstEnergy
                  Generation Corp.10.4*
              Form
                  of Waste
                  Water Facilities Loan Agreement between the Ohio Water Development
                  Authority and FirstEnergy Generation Corp. dated as of April 1,
                  2006.
  156
  
 10.5
              Notice
                  of
                  Termination Tolling Agreement dated as of April 7, 2006; Restated
                  Partial
                  Requirements Agreement, dated January 1, 2003, by and among, Metropolitan
                  Edison Company, Pennsylvania Electric Company, The Waverly Electric
                  Power
                  and Light Company and FirstEnergy Solutions Corp., as amended by
                  a First
                  Amendment to Restated Requirements Agreement, dated August 29,
                  2003 and by
                  a Second Amendment to Restated Requirements Agreement, dated June
                  8, 2004
                  (“Partial Requirements Agreement”). (Form 8-K dated April 10,
                  2006)10.6
              Form
                  of
                  Restricted Stock Agreement between FirstEnergy and A. J. Alexander,
                  dated
                  February 27, 2006.10.7
              Form
                  of
                  Restricted Stock Unit Agreement (Performance Adjusted) between
                  FirstEnergy
                  and A.J. Alexander, dated March 1, 2006.10.8
              Form
                  of
                  Restricted Stock Unit Agreement (Performance Adjusted) between
                  FirstEnergy
                  and named executive officers, dated March 1, 2006.10.9
              Form
                  of
                  Restricted Stock Unit Agreement (Discretionary) between FirstEnergy
                  and
                  R.H. Marsh, dated March 1, 2006.12
              Fixed
                  charge
                  ratios15
              Letter
                  from
                  independent registered public accounting firm31.1
              Certification
                  of chief executive officer, as adopted pursuant to Rule
                  13a-15(e)/15d-(e).31.2
              Certification
                  of chief financial officer, as adopted pursuant to Rule
                  13a-15(e)/15d-(e).32.1
              Certification
                  of chief executive officer and chief financial officer, pursuant
                  to 18
                  U.S.C. Section 1350.**OE**12
              Fixed
                  charge
                  ratios15
              Letter
                  from
                  independent registered public accounting firm31.1
              Certification
                  of chief executive officer, as adopted pursuant to Rule
                  13a-15(e)/15d-(e).31.2
              Certification
                  of chief financial officer, as adopted pursuant to Rule
                  13a-15(e)/15d-(e).32.1
              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 firm31.1
              Certification
                of chief executive officer, as adopted pursuant to Rule
                13a-15(e)/15d-(e).31.2
              Certification
                of chief financial officer, as adopted pursuant to Rule
                13a-15(e)/15d-(e).32.1
              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-(e).31.2
              Certification
                  of chief financial officer, as adopted pursuant to Rule
                  13a-15(e)/15d-(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-(e).31.2
              Certification
                  of chief financial officer, as adopted pursuant to Rule
                  13a-15(e)/15d-(e).32.1
              Certification
                  of chief executive officer and chief financial officer, pursuant
                  to 18
                  U.S.C. Section 1350.**JCP&L**12
              Fixed
                  charge
                  ratios31.2
              Certification
                  of chief financial officer, as adopted pursuant to Rule
                  13a-15(e)/15d-(e).31.3
              Certification
                  of chief executive officer, as adopted pursuant to Rule
                  13a-15(e)/15d-(e).32.2
              Certification
                  of chief executive officer and chief financial officer, pursuant
                  to 18
                  U.S.C. Section 1350.**Met-Ed**12
              Fixed
                  charge
                  ratios31.1
              Certification
                  of chief executive officer, as adopted pursuant to Rule
                  13a-15(e)/15d-(e).31.2
              Certification
                  of chief financial officer, as adopted pursuant to Rule
                  13a-15(e)/15d-(e).32.1
              Certification
                  of chief executive officer and chief financial officer, pursuant
                  to 18
                  U.S.C. Section 1350.**Penelec**12
              Fixed
                  charge
                  ratios15
              Letter
                  from
                  independent registered public accounting firm31.1
              Certification
                  of chief executive officer, as adopted pursuant to Rule
                  13a-15(e)/15d-(e).31.2
              Certification
                  of chief financial officer, as adopted pursuant to Rule
                  13a-15(e)/15d-(e).32.1
              Certification
                  of chief executive officer and chief financial officer, pursuant
                  to 18
                  U.S.C. Section 1350.*
                  Three
                  substantially similar agreements, each dated as of the same date,
                  were
                  executed and delivered by the registrant and its affiliates with
                  respect
                  to three other series of pollution control revenue refunding bonds
                  issued
                  by the Ohio Water Development Authority and the Beaver County Industrial
                  Development Authority relating to pollution control notes of FirstEnergy
                  Generation Corp. and FirstEnergy Nuclear Generation Corp. (Form
                  8-K dated
                  April 3, 2006)
 
 Pursuant
        to
        reporting requirements of respective financings, FirstEnergy, OE, JCP&L,
        Met-Ed and Penelec are required to file fixed charge ratios as an exhibit
        to
        this Form 10-Q. CEI, TE and Penn do not have similar financing reporting
        requirements and have not filed their respective fixed charge
        ratios.
  157
  
 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.
 
  158
 
 
 **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.
 
 
 
 May
        8,
        2006
 
 
 
 
 
 **FIRSTENERGY
                  CORP.**Registrant**OHIO
                  EDISON COMPANY**Registrant**THE
                  CLEVELAND ELECTRIC****ILLUMINATING
                  COMPANY**Registrant**THE
                  TOLEDO EDISON COMPANY**Registrant**PENNSYLVANIA
                  POWER COMPANY**Registrant**JERSEY
                  CENTRAL POWER & LIGHT COMPANY**Registrant**METROPOLITAN
                  EDISON COMPANY**Registrant**PENNSYLVANIA
                  ELECTRIC COMPANY**Registrant
 
 
 
 
 
 /s/Harvey
                  L.
                  WagnerHarvey L. WagnerVice
                  President, Controllerand
                  Chief Accounting Officer
  
 159