**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 June 30, 2006**
 
 **OR**
 
 **[
        ]
        TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE**
 **SECURITIES
        EXCHANGE ACT OF 1934**
 
 **For
                  the transition period from**
              
              **to**
 
 **Commission**
              **Registrant;
                  State of Incorporation;**
              **I.R.S.
                  Employer****File
                  Number**
              **Address;
                  and Telephone Number**
              **Identification
                  No.****333-21011**
              **FIRSTENERGY
                  CORP.**
              **34-1843785****(An
                  Ohio Corporation)****76
                  South Main Street****Akron,
                  OH 44308****Telephone
                  (800)736**-**3402****1-2578**
              **OHIO
                  EDISON COMPANY**
              **34-0437786****(An
                  Ohio Corporation)****c/o
                  FirstEnergy Corp.****76
                  South Main Street****Akron,
                  OH 44308****Telephone
                  (800)736**-**3402****1-2323**
              **THE
                  CLEVELAND ELECTRIC ILLUMINATING COMPANY**
              **34-0150020****(An
                  Ohio Corporation)****c/o
                  FirstEnergy Corp.****76
                  South Main Street****Akron,
                  OH 44308****Telephone
                  (800)736**-**3402****1-3583**
              **THE
                  TOLEDO EDISON COMPANY**
              **34-4375005****(An
                  Ohio Corporation)****c/o
                  FirstEnergy Corp.****76
                  South Main Street****Akron,
                  OH 44308****Telephone
                  (800)736**-**3402****1-3491**
              **PENNSYLVANIA
                  POWER COMPANY**
              **25-0718810****(A
                  Pennsylvania Corporation)****c/o
                  FirstEnergy Corp.****76
                  South Main Street****Akron,
                  OH 44308****Telephone
                  (800)736**-**3402****1-3141**
              **JERSEY
                  CENTRAL POWER & LIGHT COMPANY**
              **21-0485010****(A
                  New
                  Jersey Corporation)****c/o
                  FirstEnergy Corp.****76
                  South Main Street****Akron,
                  OH 44308****Telephone
                  (800)736**-**3402****1-446**
              **METROPOLITAN
                  EDISON COMPANY**
              **23-0870160****(A
                  Pennsylvania Corporation)****c/o
                  FirstEnergy Corp.****76
                  South Main Street****Akron,
                  OH 44308****Telephone
                  (800)736**-**3402****1-3522**
              **PENNSYLVANIA
                  ELECTRIC COMPANY**
              **25-0718085****(A
                  Pennsylvania Corporation)****c/o
                  FirstEnergy Corp.****76
                  South Main Street****Akron,
                  OH 44308****Telephone
                  (800)736**-**3402**





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





Yes (X) No (  )





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





Large
                Accelerated Filer(X)
            FirstEnergy
                Corp.Accelerated
                Filer(
                )
            N/ANon-accelerated
                Filer(X)
            Ohio
                Edison
                Company, 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
                AUGUST 7, 2006**FirstEnergy
                Corp., $.10 par value
            329,836,276Ohio
                Edison
                Company, no par value
            80The
                Cleveland
                Electric Illuminating Company, no par value
            79,590,689The
                Toledo
                Edison Company, $5 par value
            39,133,887Pennsylvania
                Power Company, $30 par value
            6,290,000Jersey
                Central
                Power & Light Company, $10 par value
            15,371,270Metropolitan
                Edison Company, no par value
            859,500Pennsylvania
                Electric Company, $20 par value
            5,290,596





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





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







**TABLE
        OF
        CONTENTS**
 
 
 
 **Pages****Glossary
                  of Terms**
              iii-v**Part
                  I.****Financial
                  Information****Items
                  1. and 2. - Financial Statements and Management’s Discussion and Analysis
                  of****Financial
                  Condition and Results of Operations.**Notes
                  to
                  Consolidated Financial Statements
              1-26**FirstEnergy
                  Corp.**Consolidated
                  Statements of Income
              27Consolidated
                  Statements of Comprehensive Income
              28Consolidated
                  Balance Sheets
              29Consolidated
                  Statements of Cash Flows
              30Report
                  of
                  Independent Registered Public Accounting Firm
              31Management's
                  Discussion and Analysis of Results of Operations and
              32-70Financial
                  Condition**Ohio
                  Edison Company**Consolidated
                  Statements of Income and Comprehensive Income
              71Consolidated
                  Balance Sheets
              72Consolidated
                  Statements of Cash Flows
              73Report
                  of
                  Independent Registered Public Accounting Firm
              74Management's
                  Discussion and Analysis of Results of Operations and
              75-87Financial
                  Condition**The
                  Cleveland Electric Illuminating Company**Consolidated
                  Statements of Income and Comprehensive Income
              88Consolidated
                  Balance Sheets
              89Consolidated
                  Statements of Cash Flows
              90Report
                  of
                  Independent Registered Public Accounting Firm
              91Management's
                  Discussion and Analysis of Results of Operations and
              92-102Financial
                  Condition**The
                  Toledo Edison Company**Consolidated
                  Statements of Income and Comprehensive Income
              103Consolidated
                  Balance Sheets
              104Consolidated
                  Statements of Cash Flows
              105Report
                  of
                  Independent Registered Public Accounting Firm
              106Management's
                  Discussion and Analysis of Results of Operations and
              107-118Financial
                  Condition**Pennsylvania
                  Power Company**ConsolidatedStatements of
                  Income
              119ConsolidatedBalance
                  Sheets
              120ConsolidatedStatements of
                  Cash Flows
              121Report
                  of
                  Independent Registered Public Accounting Firm
              122Management's
                  Discussion and Analysis of Results of Operations and
              123-130Financial
                  Condition
   i
  **TABLE
          OF
          CONTENTS (Cont'd)**
 
 
 **Pages****Jersey
                    Central Power & Light Company**Consolidated
                    Statements of Income and Comprehensive Income
                131Consolidated
                    Balance Sheets
                132Consolidated
                    Statements of Cash Flows
                133Report
                    of
                    Independent Registered Public Accounting Firm
                134Management's
                    Discussion and Analysis of Results of Operations and
                135-143Financial
                    Condition**Metropolitan
                    Edison Company**Consolidated
                    Statements of Income and Comprehensive Income
                144Consolidated
                    Balance Sheets
                145Consolidated
                    Statements of Cash Flows
                146Report
                    of
                    Independent Registered Public Accounting Firm
                147Management's
                    Discussion and Analysis of Results of Operations and
                148-157Financial
                    Condition**Pennsylvania
                    Electric Company**Consolidated
                    Statements of Income and Comprehensive Income
                158Consolidated
                    Balance Sheets
                159Consolidated
                    Statements of Cash Flows
                160Report
                    of
                    Independent Registered Public Accounting Firm
                161Management's
                    Discussion and Analysis of Results of Operations and
                162-170Financial
                    Condition**Item
                    3.****Quantitative
                    and Qualitative Disclosures About Market Risk.**
                171**Item
                    4.****Controls
                    and Procedures.**
                171**Part
                    II.****Other
                    Information****Item
                    1.****Legal
                    Proceedings.**
                172**Item
                    1A.****Risk
                    Factors.**
                172**Item
                    2.****Unregistered
                    Sales of Equity Securities and Use of Proceeds.**
                172**Item
                    4.****Submission
                    of Matters to a Vote of Security Holders.**
                172**Item
                    6.****Exhibits.**
                173-174
 ii
 **GLOSSARY
              OF
              TERMS**





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





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


iii
 **GLOSSARY
            OF
            TERMS, Cont'd.**





DRA
            Division
                of
                the Ratepayer AdvocateECAR
            East
                Central
                Area Reliability Coordination AgreementEDCP
            Executive
                Deferred Compensation PlanEITF
            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 2005ERO
            Electric
                Reliability OrganizationESOP
            Employee
                Stock
                Ownership PlanFASB
            Financial
                Accounting Standards BoardFERC
            Federal
                Energy
                Regulatory CommissionFIN
            FASB
                InterpretationFIN
                46(R)
            FIN
                46
                (revised December 2003), "Consolidation of Variable Interest
                Entities"FIN
                46(R)-6
            FIN
                46(R)-6,
                “Determining the Variability to be Considered in Applying FASB
                interpretation No. 46(R)”FIN
                47
            FIN
                47,
                "Accounting for Conditional Asset Retirement Obligations - an
                interpretation of FASB Statement No. 143"FIN
                48
            FIN
                48,
                “Accounting for Uncertainty in Income Taxes - an interpretation of
                FASB
                Statement No.109”FMB
            First
                Mortgage
                BondsFSP
            FASB
                Staff
                PositionGAAP
            Accounting
                Principles Generally Accepted in the United StatesGCAF
            Generation
                Charge Adjustment FactorGHG
            Greenhouse
                GasesKWH
            Kilowatt-hoursLOC
            Letter
                of
                CreditLTIP
            Long-Term
                Incentive ProgramMEIUG
            Met-Ed
                Industrial Users GroupMISO
            Midwest
                Independent Transmission System Operator, Inc.Moody’s
            Moody’s
                Investors ServiceMOU
            Memorandum
                of
                UnderstandingMTC
            Market
                Transition ChargeMW
            MegawattsNAAQS
            National
                Ambient Air Quality StandardsNERC
            North
                American
                Electric Reliability CouncilNJBPU
            New
                Jersey
                Board of Public UtilitiesNOAC
            Northwest
                Ohio
                Aggregation CoalitionNOPR
            Notice
                of
                Proposed RulemakingNOV
            Notices
                of
                ViolationNOX
            Nitrogen
                OxideNRC
            Nuclear
                Regulatory CommissionNUG
            Non-Utility
                GenerationNUGC
            Non-Utility
                Generation ChargeOCA
            Office
                of
                Consumer AdvocateOCC
            Office
                of the
                Ohio Consumers' CounselOCI
            Other
                Comprehensive IncomeOPEB
            Other
                Post-Employment BenefitsOSBA
            Office
                of
                Small Business AdvocateOTS
            Office
                of
                Trial StaffPaDEP
            Pennsylvania
                Department of Environmental ProtectionPCAOB
            Public
                Company
                Accounting Oversight BoardPICA
            Penelec
                Industrial Customer AssociationPJM
            PJM
                Interconnection L. L. C.PLR
            Provider
                of
                Last ResortPPUC
            Pennsylvania
                Public Utility CommissionPRP
            Potentially
                Responsible PartyPUCO
            Public
                Utilities Commission of OhioPUHCA
            Public
                Utility
                Holding Company Act of 1935RCP
            Rate
                Certainty
                PlanRFP
            Request
                for
                ProposalRSP
            Rate
                Stabilization PlanRTC
            Regulatory
                Transition ChargeRTO
            Regional
                Transmission OrganizationRTOR
            Through
                and
                Out RatesS&P
            Standard
&
                Poor’s Ratings ServiceSAIFI
            System
                Average
                Interruption Frequency IndexSBC
            Societal
                Benefits ChargeSEC
            U.S.
                Securities and Exchange CommissionSECA
            Seams
                Elimination Cost AdjustmentSFAS
            Statement
                of
                Financial Accounting StandardsSFAS
                123
            SFAS
                No. 123,
                "Accounting for Stock-Based Compensation"SFAS
                123(R)
            SFAS
                No.
                123(R), "Share-Based Payment"SFAS
                133
            SFAS
                No. 133,
                “Accounting for Derivative Instruments and Hedging
                Activities”SFAS
                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"SO2
            Sulfur
                DioxideSRM
            Special
                Reliablity MasterTBC
            Transition
                Bond ChargeTMI-2
            Three
                Mile
                Island Unit 2VIE
            Variable
                Interest EntityVMEP
            Vegetation
                Management Enhancement Project





iv


**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.





**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.
      The following table reconciles the computation of basic and diluted earnings
      per
      share of common stock before discontinued operations:


1





**Three
                Months Ended**
            
            **Six
                Months Ended****June
                30,**
            
            **June
                30,****Reconciliation
                of Basic and Diluted Earnings per Share**
            
            **2006**
            
            **2005**
            
            **2006**
            
            **2005*****(In
                millions, except per share amounts)***Income
                Before
                Discontinued Operations
            
            $
            304
            
            $
            179
            
            $
            525
            
            $
            320Less:
                Redemption premium on subsidiary preferred stock
            
            
            (3
            )
            
            -
            
            
            (3
            )
            
            -Earnings
                on
                Common Stock Before Discontinued Operations
            
            $
            301
            
            $
            179
            
            $
            522
            
            $
            320Weighted
                Average Shares of Common Stock Outstanding:Denominator
                for basic earnings per share
            
            
            328
            
            
            328
            
            
            328
            
            
            328Assumed
                exercise of dilutive stock options and awards
            
            
            2
            
            
            2
            
            
            2
            
            
            2Denominator
                for diluted earnings per share
            
            
            330
            
            
            330
            
            
            330
            
            
            330Earnings
                Before Discontinued Operations per Common Share:Basic
            
            $
            0.92
            
            $
            0.54
            
            $
            1.59
            
            $
            0.98Diluted
            
            $
            0.91
            
            $
            0.54
            
            $
            1.58
            
            $
            0.97





**3.
      -
      GOODWILL**





FirstEnergy's
      goodwill primarily relates to its regulated services segment. In the six months
      ended June 30, 2006, FirstEnergy adjusted goodwill related to the
      divestiture of a non-core asset (62% interest in MYR), a successful tax claim
      relating to the former Centerior companies, and an adjustment to the former
      GPU
      companies due to the realization of a tax benefit that had been reserved in
      purchase accounting. Adjustments to goodwill in the second quarter of 2006
      were
      immaterial. The following table reconciles changes to goodwill
      for the six months ended June 30, 2006.





**Goodwill
                Reconciliation**
            
            **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
                June 30, 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. In June 2006, FirstEnergy sold an additional 1.67% interest. As a
      result of the March sale, FirstEnergy deconsolidated MYR in the first quarter
      of
      2006 and accounts for its remaining 38.33% interest under the equity
      method.




In
      March 2005, FirstEnergy sold 51% of
      its interest in FirstCom for an after-tax gain of $4 million. FirstEnergy
      accounts for its remaining 31.85% interest in FirstCom under the equity
      method.




During
      the first six
      months of 2005, FirstEnergy sold three FSG subsidiaries (Cranston, Elliott-Lewis
      and Spectrum), an MYR subsidiary (Power Piping) and FES' retail natural gas
      business, resulting in aggregate after-tax gains of $17 million. The
      remaining FSG subsidiaries continue to be actively marketed and qualify as
      assets held for sale in accordance with SFAS 144 because FirstEnergy
      anticipates that the transfer of these remaining FSG assets, with a net carrying
      value of $48 million as of June 30, 2006, will qualify for recognition
      as completed sales within one year. As of June 30, 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.





Net
      results
      (including the gains on sales of assets discussed above) for Cranston,
      Elliott-Lewis, Power Piping and FES' retail natural gas business of $(1) million
      and $18 million for the three months and six months ended June 30, 2005,
      respectively, are reported as discontinued operations on FirstEnergy's
      Consolidated Statements of Income. Pre-tax operating results for these entities
      were $(2) million and $2 million for the three months and six months ended
      June 30, 2005, respectively. Revenues associated with discontinued
      operations for the three months and six months ended June 30, 2005 were $11
      million and $206 million, respectively. The following table summarizes the
      sources of income from discontinued operations for the three months and six
      months ended June 30, 2005:


2





**Three
                Months**
            
            
            **Six
                Months***(****In
                millions)***Discontinued
                Operations (Net of tax)Gain
                on
                sale:Natural
                gas
                business
            
            $
            -
            
            $
            5FSG
                and MYR
                subsidiaries
            
            
            -
            
            
            12Reclassification
                of operating income (loss)
            
            
            (1
            )
            
            1Total
            
            $
            (1
            )
            $
            18





**5.
      -
      DERIVATIVE INSTRUMENTS**




FirstEnergy
      is
      exposed to financial risks resulting from the fluctuation of interest rates
      and
      commodity prices, including prices for electricity, natural gas, coal and energy
      transmission. To manage the volatility relating to these exposures, FirstEnergy
      uses a variety of non-derivative and derivative instruments, including forward
      contracts, options, futures contracts and swaps. The derivatives are used
      principally for hedging purposes. FirstEnergy’s Risk Policy Committee, comprised
      of members of senior management, provides general management oversight to risk
      management activities. The Committee is responsible for promoting the effective
      design and implementation of sound risk management programs and oversees
      compliance with corporate risk management policies and established risk
      management practices.




FirstEnergy
      accounts
      for derivative instruments on its Consolidated Balance Sheet at their fair
      value
      unless they meet the normal purchase and normal sales exception criterion.
      Derivatives that meet that criterion are accounted for on the accrual basis.
      The
      changes in the fair value of derivative instruments that do not meet the normal
      purchase and sales criterion are recorded in current earnings, in AOCL, or
      as
      part of the value of the hedged item, depending on whether or not it is
      designated as part of a hedge transaction, the nature of the hedge transaction
      and hedge effectiveness.




FirstEnergy
      hedges
      anticipated transactions using cash flow hedges. Such transactions include
      hedges of anticipated electricity and natural gas purchases and anticipated
      interest payments associated with future debt issues. The effective portion
      of
      such hedges are initially recorded in equity as other comprehensive income
      or
      loss and are subsequently included in net income as the underlying hedged
      commodities are delivered or interest payments are made. Gains and losses from
      any ineffective portion of cash flow hedges are included directly in earnings.





The
      net deferred
      losses of $30 million included in AOCL as of June 30, 2006, for derivative
      hedging activity, as compared to the December 31, 2005 balance of $78
      million of net deferred losses, resulted from a net $35 million decrease
      related to current hedging activity and a $13 million decrease due to net hedge
      losses included in earnings during the six months ended June 30, 2006.
      Approximately $9 million (after tax) of the net deferred losses on derivative
      instruments in AOCL as of June 30, 2006 is expected to be reclassified to
      earnings during the next twelve months as hedged transactions occur. The fair
      value of these derivative instruments fluctuate from period to period based
      on
      various market factors.





FirstEnergy
      has
      entered into swaps that have been designated as fair value hedges of fixed-rate,
      long-term debt issues to protect against the risk of changes in the fair value
      of fixed-rate debt instruments due to lower interest rates. Swap maturities,
      call options, fixed interest rates received, and interest payment dates match
      those of the underlying debt obligations. During the first six months 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 June 30, 2006, the aggregate notional value of interest
      rate swap agreements outstanding was $750 million.





During
      2005 and the
      first six months of 2006, FirstEnergy entered into several forward starting
      swap
      agreements (forward swaps) in order to hedge a portion of the consolidated
      interest rate risk associated with the anticipated issuances of fixed-rate,
      long-term debt securities for one or more of its subsidiaries during 2006 -
      2008
      as outstanding debt matures. These derivatives are treated as cash flow hedges,
      protecting against the risk of changes in future interest payments resulting
      from changes in benchmark U.S. Treasury rates between the date of hedge
      inception and the date of the debt issuance. FirstEnergy revised the tenor
      and
      timing of its financing plan during the first six months of 2006. FirstEnergy
      terminated and revised its forward swaps, ultimately terminating swaps with
      an
      aggregate notional value of $600 million as its subsidiaries issued long term
      debt in the second quarter. As required by SFAS 133, FirstEnergy assessed the
      amount of ineffectiveness of the hedges at each termination. FirstEnergy
      received cash gains of $41 million, of which approximately $6 million ($4
      million net of tax) was deemed ineffective and recognized in earnings in the
      first six months of 2006. The remaining gain deemed effective in the amount
      of
      approximately $35 million ($22 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 June 30, 2006, FirstEnergy had
      forward swaps with an aggregate notional amount of $550million and a long-term
      debt securities fair value of $29 million.


3








**6.
      - STOCK
      BASED COMPENSATION**





Effective
      January 1,
      2006, FirstEnergy adopted SFAS 123(R), which requires the expensing of
      stock-based compensation. Under SFAS 123(R), all share-based compensation cost
      is measured at the grant date based on the fair value of the award, and is
      recognized as an expense over the employee’s requisite service period.
      FirstEnergy adopted the modified prospective method, under which compensation
      expense recognized in the second quarter and six months ended June 30, 2006
      included the expense for all share-based payments granted prior to but not
      yet
      vested as of January 1, 2006. Results for prior periods were not restated.





Prior
      to the
      adoption of SFAS 123(R) on January, 1, 2006, FirstEnergy’s LTIP, EDCP, ESOP, and
      DCPD stock-based compensation programs were accounted for under the recognition
      and measurement principles of APB 25 and related interpretations. The LTIP
      includes four stock-based compensation programs - restricted stock, restricted
      stock units, stock options and performance shares.





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 granted since the third quarter of
      2004. Consequently, the impact of adopting SFAS 123(R) was not material to
      FirstEnergy's net income and earnings per share in the second quarter and six
      months ended June 30, 2006. In the year of adoption, all disclosures prescribed
      by SFAS 123(R) are required to be included in both the quarterly Form 10-Q
      filings as well as the annual Form 10-K filing. However, due to the immaterial
      impact of the adoption of SFAS 123(R) on FirstEnergy's financial results, only
      condensed disclosure has been provided. Reference is made to FirstEnergy’s
      annual report on Form 10-K for the year ended December 31, 2005 for expanded
      annual disclosure.





The
      following table
      illustrates the effect on net income and earnings per share for the three months
      and six months ended June 30, 2005, as if FirstEnergy had adopted SFAS
      123(R) as of January 1, 2005:





**Three
                Months**
            
            **Six
                Months*****(In
                millions, except per share amounts)***Net
                Income, as
                reported
            
            $
            178
            
            $
            338Add
                back
                compensation expensereported
                in
                net income, net of tax (based onAPB
                25)*
            
            
            14
            
            
            22Deduct
                compensation expense basedupon
                estimated
                fair value, net of tax*
            
            
            (17
            )
            
            (28
            )Pro
                forma net
                income
            
            $
            175
            
            $
            332Earnings
                Per
                Share of Common Stock -BasicAs
                Reported
            
            $
            0.54
            
            $
            1.03ProForma
            
            $
            0.53
            
            $
            1.01DilutedAs
                Reported
            
            $
            0.54
            
            $
            1.02Pro
                Forma
            
            $
            0.53
            
            $
            1.01





*  Includes
      restricted
      stock, restricted stock units, stock options, performance


shares,
      ESOP, EDCP
      and DCPD.





**7.
      - ASSET
      RETIREMENT OBLIGATIONS**





FirstEnergy
      has
      recognized applicable legal obligations under SFAS 143 for nuclear power plant
      decommissioning, reclamation of a sludge disposal pond and closure of two coal
      ash disposal sites. In addition, FirstEnergy has recognized conditional
      retirement obligations (primarily for asbestos remediation) in accordance with
      FIN 47, which was implemented on December 31, 2005. Had FIN 47 been
      applied in the six months ended June 30, 2005, the impact on earnings would
      have been immaterial.


4





The
      ARO liability of $1.2 billion
      as of June 30, 2006 primarily relates to the nuclear decommissioning of the
      Beaver Valley, Davis-Besse, Perry and TMI-2 nuclear generating facilities.
      The
      obligation to decommission these units was developed based on site specific
      studies performed by an independent engineer. FirstEnergy uses an expected
      cash
      flow approach to measure the fair value of the nuclear decommissioning ARO.




FirstEnergy maintains nuclear decommissioning trust funds that are legally
      restricted for purposes of settling the nuclear decommissioning ARO. As of
      June
      30, 2006, the fair value of the decommissioning trust assets was $1.8 billion.





The
      following tables
      analyze changes to the ARO balances during the three months and six months
      ended
      June 30, 2006 and 2005, respectively.





**Three
                Months Ended**
            
            **FirstEnergy**
            
            **OE**
            
            **CEI**
            
            **TE**
            
            **Penn**
            
            **JCP&L**
            
            **Met-Ed**
            
            **Penelec*****(In
                millions)*****ARO
                Reconciliation**Balance,
                April
                1, 2006
            
            $
            1,148
            
            $
            84
            
            $
            8
            
            $
            25
            
            $
            -
            
            $
            81
            
            $
            144
            
            $
            73Liabilities
                incurred
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Liabilities
                settled
            
            
            (6
            )
            
            -
            
            
            (6
            )
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Accretion
            
            
            18
            
            
            1
            
            
            -
            
            
            1
            
            
            -
            
            
            1
            
            
            2
            
            
            1Revisions
                in
                estimatedcashflows
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Balance,
                June
                30, 2006
            
            $
            1,160
            
            $
            85
            
            $
            2
            
            $
            26
            
            $
            -
            
            $
            82
            
            $
            146
            
            $
            74Balance,
                April
                1, 2005
            
            $
            1,095
            
            $
            204
            
            $
            276
            
            $
            198
            
            $
            141
            
            $
            74
            
            $
            135
            
            $
            67Liabilities
                incurred
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Liabilities
                settled
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Accretion
            
            
            18
            
            
            4
            
            
            5
            
            
            3
            
            
            2
            
            
            1
            
            
            2
            
            
            1Revisions
                in
                estimatedcashflows
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Balance,
                June
                30, 2005
            
            $
            1,113
            
            $
            208
            
            $
            281
            
            $
            201
            
            $
            143
            
            $
            75
            
            $
            137
            
            $
            68








**Six
                Months Ended**
            
            **FirstEnergy**
            
            **OE**
            
            **CEI**
            
            **TE**
            
            **Penn**
            
            **JCP&L**
            
            **Met-Ed**
            
            **Penelec*****(In
                millions)*****ARO
                Reconciliation**Balance,
                January 1, 2006
            
            $
            1,126
            
            $
            83
            
            $
            8
            
            $
            25
            
            $
            -
            
            $
            80
            
            $
            142
            
            $
            72Liabilities
                incurred
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Liabilities
                settled
            
            
            (6
            )
            
            -
            
            
            (6
            )
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Accretion
            
            
            36
            
            
            2
            
            
            -
            
            
            1
            
            
            -
            
            
            2
            
            
            4
            
            
            2Revisions
                in
                estimatedcashflows
            
            
            4
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Balance,
                June
                30, 2006
            
            $
            1,160
            
            $
            85
            
            $
            2
            
            $
            26
            
            $
            -
            
            $
            82
            
            $
            146
            
            $
            74Balance,
                January 1, 2005
            
            $
            1,078
            
            $
            201
            
            $
            272
            
            $
            195
            
            $
            138
            
            $
            72
            
            $
            133
            
            $
            67Liabilities
                incurred
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Liabilities
                settled
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Accretion
            
            
            35
            
            
            7
            
            
            9
            
            
            6
            
            
            5
            
            
            3
            
            
            4
            
            
            1Revisions
                in
                estimatedcashflows
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Balance,
                June
                30, 2005
            
            $
            1,113
            
            $
            208
            
            $
            281
            
            $
            201
            
            $
            143
            
            $
            75
            
            $
            137
            
            $
            68





**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.


5





The
      components of
      FirstEnergy's net periodic pension and other postretirement benefit costs
      (including amounts capitalized) for the three months and six months ended June
      30, 2006 and 2005 consisted of the following:





**Three
                Months Ended**
            **Six
                Months Ended****June
                30,**
            
            **June
                30,****Pension
                Benefits**
            
            **2006**
            
            **2005**
            
            **2006**
            
            **2005*****(In
                millions)***Service
                cost
            
            $
            21
            
            $
            19
            
            $
            41
            
            $
            38Interest
                cost
            
            
            66
            
            
            64
            
            
            133
            
            
            128Expected
                return on plan assets
            
            
            (99
            )
            
            (86
            )
            
            (198
            )
            
            (173
            )Amortization
                of prior service cost
            
            
            2
            
            
            2
            
            
            5
            
            
            4Recognized
                net
                actuarial loss
            
            
            15
            
            
            9
            
            
            29
            
            
            18Net
                periodic
                cost
            
            $
            5
            
            $
            8
            
            $
            10
            
            $
            15





**Three
                Months Ended**
            **Six
                Months Ended****June
                30,**
            
            **June
                30,****Other
                Postretirement Benefits**
            
            **2006**
            
            **2005**
            
            **2006**
            
            **2005*****(In
                millions)***Service
                cost
            
            $
            9
            
            $
            10
            
            $
            17
            
            $
            20Interest
                cost
            
            
            26
            
            
            27
            
            
            52
            
            
            55Expected
                return on plan assets
            
            
            (12
            )
            
            (11
            )
            
            (23
            )
            
            (22
            )Amortization
                of prior service cost
            
            
            (19
            )
            
            (11
            )
            
            (37
            )
            
            (22
            )Recognized
                net
                actuarial loss
            
            
            14
            
            
            10
            
            
            27
            
            
            20Net
                periodic
                cost
            
            $
            18
            
            $
            25
            
            $
            36
            
            $
            51





Pension
      and
      postretirement benefit obligations are allocated to FirstEnergy’s subsidiaries
      employing the plan participants. FirstEnergy’s subsidiaries capitalize employee
      benefits related to construction projects. The net periodic pension costs
      (credits) and net periodic postretirement benefit costs (including amounts
      capitalized) recognized by each of the Companies for the three months and six
      months ended June 30, 2006 and 2005 were as follows:





**Three
                Months Ended**
            
            **Six
                Months Ended****June
                30,**
            
            **June
                30,****Pension
                Benefit Cost (Credit)**
            
            **2006**
            
            **2005**
            
            **2006**
            
            **2005*****(In
                millions)***OE
            
            $
            (1.1
            )
            $
            0.2
            
            $
            (2.1
            )
            $
            0.4Penn
            
            
            (0.4
            )
            
            (0.2
            )
            
            (0.8
            )
            
            (0.4
            )CEI
            
            
            1.0
            
            
            0.3
            
            
            1.9
            
            
            0.7TE
            
            
            0.2
            
            
            0.3
            
            
            0.4
            
            
            0.6JCP&L
            
            
            (1.4
            )
            
            (0.3
            )
            
            (2.7
            )
            
            (0.5
            )Met-Ed
            
            
            (1.7
            )
            
            (1.1
            )
            
            (3.5
            )
            
            (2.2
            )Penelec
            
            
            (1.3
            )
            
            (1.3
            )
            
            (2.7
            )
            
            (2.7
            )Other
                FirstEnergy subsidiaries
            
            
            9.9
            
            
            9.6
            
            
            20.0
            
            
            19.1$
            5.2
            
            $
            7.5
            
            $
            10.5
            
            $
            15.0





**Three
                Months Ended**
            
            **Six
                Months Ended****June
                30,**
            
            **June
                30,****Other
                Postretirement Benefit Cost**
            
            **2006**
            
            **2005**
            
            **2006**
            
            **2005*****(In
                millions)***OE
            
            $
            3.4
            
            $
            5.8
            
            $
            6.8
            
            $
            11.5Penn
            
            
            0.8
            
            
            1.2
            
            
            1.6
            
            
            2.4CEI
            
            
            2.8
            
            
            3.8
            
            
            5.5
            
            
            7.6TE
            
            
            2.0
            
            
            2.2
            
            
            4.0
            
            
            4.3JCP&L
            
            
            0.6
            
            
            1.5
            
            
            1.2
            
            
            4.2Met-Ed
            
            
            0.7
            
            
            0.4
            
            
            1.5
            
            
            0.8Penelec
            
            
            1.8
            
            
            2.0
            
            
            3.6
            
            
            4.0Other
                FirstEnergy subsidiaries
            
            
            6.1
            
            
            8.1
            
            
            12.1
            
            
            16.2$
            18.2
            
            $
            25.0
            
            $
            36.3
            
            $
            51.0





6


**9.
      -
      VARIABLE INTEREST ENTITIES**




FIN 46R addresses the consolidation of VIEs, including special-purpose entities,
      that are not controlled through voting interests or in which the equity
      investors do not bear the entity's residual economic risks and rewards.
      FirstEnergy and its subsidiaries consolidate VIEs when they are determined
      to be
      the VIE's primary beneficiary as defined by FIN 46R.





**Leases**




FirstEnergy’s
      consolidated financial statements include PNBV and Shippingport, VIEs created
      in
      1996 and 1997, respectively, to refinance debt originally issued in connection
      with sale and leaseback transactions. PNBV and Shippingport financial data
      are
      included in the consolidated financial statements of OE and CEI, respectively.




PNBV was established to purchase a portion of the lease obligation bonds issued
      in connection with OE’s 1987 sale and leaseback of its interests in the Perry
      Plant and Beaver Valley Unit 2. OE used debt and available funds to purchase
      the
      notes issued by PNBV. Ownership of PNBV includes a 3% equity interest by an
      unaffiliated third party and a 3% equity interest held by OES Ventures, a wholly
      owned subsidiary of OE. Shippingport was established to purchase all of the
      lease obligation bonds issued in connection with CEI’s and TE’s Bruce Mansfield
      Plant sale and leaseback transaction in 1987. CEI and TE used debt and available
      funds to purchase the notes issued by Shippingport.




OE, CEI and TE are exposed to losses under the applicable sale-leaseback
      agreements upon the occurrence of certain contingent events that each company
      considers unlikely to occur. OE, CEI and TE each have a maximum exposure to
      loss
      under these provisions of approximately $1 billion, which represents the
      net amount of casualty value payments upon the occurrence of specified casualty
      events that render the applicable plant worthless. Under the applicable
      sale-leaseback agreements, OE, CEI and TE have net minimum discounted lease
      payments of $640 million, $98 million and $498 million, respectively,
      that would not be payable if the casualty value payments are made.





**Power
      Purchase Agreements**




In accordance with FIN 46R, FirstEnergy evaluated its power purchase agreements
      and determined that certain NUG entities may be VIEs to the extent they own
      a
      plant that sells substantially all of its output to the Companies and the
      contract price for power is correlated with the plant’s variable costs of
      production. FirstEnergy, through its subsidiaries JCP&L, Met-Ed and Penelec,
      maintains approximately 30 long-term power purchase agreements with NUG
      entities. The agreements were entered into pursuant to the Public Utility
      Regulatory Policies Act of 1978. FirstEnergy was not involved in the creation
      of, and has no equity or debt invested in, these entities.




FirstEnergy has determined that for all but eight of these entities, neither
      JCP&L, Met-Ed nor Penelec have variable interests in the entities or the
      entities are governmental or not-for-profit organizations not within the scope
      of FIN 46R. JCP&L, Met-Ed or Penelec may hold variable interests in the
      remaining eight entities, which sell their output at variable prices that
      correlate to some extent with the operating costs of the plants. As required
      by
      FIN 46R, FirstEnergy periodically requests from these eight entities the
      information necessary to determine whether they are VIEs or whether JCP&L,
      Met-Ed or Penelec is the primary beneficiary. FirstEnergy has been unable to
      obtain the requested information, which in most cases was deemed by the
      requested entity to be proprietary. As such, FirstEnergy applied the scope
      exception that exempts enterprises unable to obtain the necessary information
      to
      evaluate entities under FIN 46R.





Since
      FirstEnergy
      has no equity or debt interests in the NUG entities, its maximum exposure to
      loss relates primarily to the above-market costs it incurs for power.
      FirstEnergy expects any above-market costs it incurs to be recovered from
      customers. As of June 30, 2006, the net above-market loss liability projected
      for these eight NUG agreements was $74 million. Purchased power costs from
      these entities during the three months and six months ended June 30, 2006 and
      2005 are shown in the following table:




**Three
                Months Ended**
            
            **Six
                Months Ended****June
                30,**
            
            **June
                30,****2006**
            
            **2005**
            
            **2006**
            
            **2005*****(In
                millions)***JCP&L
            $
            19
            
            $
            21
            
            $
            34
            
            $
            42Met-Ed
            
            16
            
            
            14
            
            
            33
            
            
            30Penelec
            
            7
            
            
            7
            
            
            14
            
            
            14Total
            $
            42
            
            $
            42
            
            $
            81
            
            $
            86





7





**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 June 30, 2006, outstanding guarantees and other
      assurances totaled approximately $3.5 billion consisting of contract
      guarantees ($1.9 billion), surety bonds ($0.1 billion) and LOCs
      ($1.5 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 $0.8 billion (included in the $1.9 billion discussed
      above) as of June 30, 2006 would increase amounts otherwise payable by
      FirstEnergy to meet its obligations incurred in connection with financings
      and
      ongoing energy and energy-related activities.





While
      these types of
      guarantees are normally parental commitments for the future payment of
      subsidiary obligations, subsequent to the occurrence of a credit
      rating-downgrade or “material adverse event” the immediate posting of cash
      collateral or provision of an LOC may be required of the subsidiary. As of
      June
      30, 2006, FirstEnergy's maximum exposure under these collateral provisions
      was
      $501 million.





Most
      of
      FirstEnergy's surety bonds are backed by various indemnities common within
      the
      insurance industry. Surety bonds and related FirstEnergy guarantees of $146
      million provide additional assurance to outside parties that contractual and
      statutory obligations will be met in a number of areas including construction
      jobs, environmental commitments and various retail transactions.





The
      Companies, with
      the exception of TE and JCP&L, each have a wholly owned subsidiary whose
      borrowings are secured by customer accounts receivable purchased from its
      respective parent company. The CEI subsidiary's borrowings are also secured
      by
      customer accounts receivable purchased from TE. Each subsidiary company has
      its
      own receivables financing arrangement and, as a separate legal entity with
      separate creditors, would have to satisfy its obligations to creditors before
      any of its remaining assets could be available to its parent
      company.




**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








8




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
      June 30, 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 FirstEnergy with regard to air and water
      quality and other environmental matters. The effects of compliance on the
      Companies with regard to environmental matters could have a material adverse
      effect on FirstEnergy's earnings and competitive position to the extent that
      it
      competes with companies that are not subject to such regulations and therefore
      do not bear the risk of costs associated with compliance, or failure to comply,
      with such regulations. Overall, FirstEnergy believes it is in compliance with
      existing regulations but is unable to predict future changes in regulatory
      policies and what, if any, the effects of such changes would be. FirstEnergy
      estimates additional capital expenditures for environmental compliance of
      approximately $1.8 billion for 2006 through 2010.




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




On December 1, 2005, FirstEnergy issued a comprehensive report to shareholders
      regarding air emissions regulations and an assessment of its future risks and
      mitigation efforts.





*Clean
      Air Act
      Compliance*




FirstEnergy is required to meet federally approved SO 2 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.




The EPA Region 5 issued a Finding of Violation and NOV to the Bay Shore Power
      Plant dated June 15, 2006 alleging violations to various sections of the Clean
      Air Act. A meeting has been scheduled for August 8, 2006 to discuss the alleged
      violations with the EPA.




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.





*National
      Ambient
      Air Quality Standards*




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


9





*Mercury
      Emissions*




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




The model rules for both CAIR and CAMR contemplate an input-based methodology
      to
      allocate allowances to affected facilities. Under this approach, allowances
      would be allocated based on the amount of fuel consumed by the affected sources.
      FirstEnergy would prefer an output-based generation-neutral methodology in
      which
      allowances are allocated based on megawatts of power produced. Since 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.




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





*W.
      H. Sammis
      Plant*




In 1999 and 2000, the EPA issued NOV or Compliance Orders to nine utilities
      alleging violations of the Clean Air Act based on operation and maintenance
      of
      44 power plants, including the W. H. Sammis Plant, which was owned at that
      time
      by OE and Penn. In addition, the DOJ filed eight civil complaints against
      various investor-owned utilities, including a complaint against OE and Penn
      in
      the U.S. District Court for the Southern District of Ohio. These cases are
      referred to as New Source Review cases. On March 18, 2005, OE and Penn
      announced that they had reached a settlement with the EPA, the DOJ and three
      states (Connecticut, New Jersey, and New York) that resolved all issues related
      to the W. H. Sammis Plant New Source Review litigation. This settlement
      agreement was approved by the Court on July 11, 2005, and requires
      reductions of NO X and SO 2 emissions at the
      W. H. Sammis Plant and other coal fired plants through the installation of
      pollution control devices and provides for stipulated penalties for failure
      to
      install and operate such pollution controls in accordance with that agreement.
      Consequently, if FirstEnergy fails to install such pollution control devices,
      for any reason, including, but not limited to, the failure of any third-party
      contractor to timely meet its delivery obligations for such devices, FirstEnergy
      could be exposed to penalties under the settlement agreement. Capital
      expenditures necessary to meet those requirements are currently estimated to
      be
      $1.5 billion (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 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.





*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.


10




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





*Clean
      Water
      Act*




Various water quality regulations, the majority of which are the result of
      the
      federal Clean Water Act and its amendments, apply to FirstEnergy's plants.
      In
      addition, Ohio, New Jersey and Pennsylvania have water quality standards
      applicable to FirstEnergy's operations. As provided in the Clean Water Act,
      authority to grant federal National Pollutant Discharge Elimination System
      water
      discharge permits can be assumed by a state. Ohio, New Jersey and Pennsylvania
      have assumed such authority.




On September 7, 2004, the EPA established new performance standards under
      Section 316(b) of the Clean Water Act for reducing impacts on fish and shellfish
      from cooling water intake structures at certain existing large electric
      generating plants. The regulations call for reductions in impingement mortality,
      when aquatic organisms are pinned against screens or other parts of a cooling
      water intake system, and entrainment, which occurs when aquatic species are
      drawn into a facility's cooling water system. FirstEnergy is conducting
      comprehensive demonstration studies, due in 2008, to determine the operational
      measures, equipment or restoration activities, if any, necessary for compliance
      by its facilities with the performance standards. FirstEnergy is unable to
      predict the outcome of such studies. Depending on the outcome of such studies,
      the future cost of compliance with these standards may require material capital
      expenditures.





*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 June
      30,
      2006, based on estimates of the total costs of cleanup, the Companies'
      proportionate responsibility for such costs and the financial ability of other
      unaffiliated entities to pay. In addition, JCP&L has accrued liabilities for
      environmental remediation of former manufactured gas plants in New Jersey;
      those
      costs are being recovered by JCP&L through a non-bypassable SBC. Total
      liabilities of approximately $70 million (JCP&L - $55 million,
      CEI - $2 million,
      and other subsidiaries - $13 million)
      have been accrued through June 30, 2006.





**(C)**  **OTHER
      LEGAL
      PROCEEDINGS**





*Power
      Outages
      and Related Litigation*




In
      July 1999, the Mid-Atlantic States experienced a severe heat wave, which
      resulted in power outages throughout the service territories of many electric
      utilities, including JCP&L's territory. In an investigation into the causes
      of the outages and the reliability of the transmission and distribution systems
      of all four of New Jersey’s electric utilities, the NJBPU concluded that there
      was not a prima facie case demonstrating that, overall, JCP&L provided
      unsafe, inadequate or improper service to its customers. Two class action
      lawsuits (subsequently consolidated into a single proceeding) were filed in
      New
      Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU
      companies, seeking compensatory and punitive damages arising from the July
      1999
      service interruptions in the JCP&L territory.




In August 2002, the trial court granted partial summary judgment to JCP&L
      and dismissed the plaintiffs' claims for consumer fraud, common law fraud,
      negligent misrepresentation, and strict product liability. In November 2003,
      the
      trial court granted JCP&L's motion to decertify the class and denied
      plaintiffs' motion to permit into evidence their class-wide damage model
      indicating damages in excess of $50 million. These class decertification and
      damage rulings were appealed to the Appellate Division. The Appellate Division
      issued a decision on July 8, 2004, affirming the decertification of the
      originally certified class, but remanding for certification of a class limited
      to those customers directly impacted by the outages of JCP&L transformers in
      Red Bank, New Jersey. 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
      June 30, 2006.


11


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




FirstEnergy
      companies also are defending six separate complaint cases before the PUCO
      relating to the August 14, 2003 power 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. Three other pending PUCO complaint cases were filed by various
      insurance carriers either in their own name as subrogees or in the name of
      their
      insured. In each of these three cases, the carrier seeks reimbursement from
      various FirstEnergy companies (and, in one case, from PJM, MISO and American
      Electric Power Company, Inc., as well) for claims paid to insureds for
      damages allegedly arising as a result of the loss of power on August 14,
      2003. The listed insureds in these cases, in many instances, are not customers
      of any FirstEnergy company. The sixth case involves the claim of a non-customer
      seeking reimbursement for losses incurred when its store was burglarized on
      August 14, 2003. FirstEnergy filed a Motion to Dismiss on June 13, 2006. It
      is currently expected that this case will be summarily dismissed, although
      the
      Motion is still pending. 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 as a defendant; ruled that
      the
      U.S.-Canada Power System Outage Task Force Report was not admissible into
      evidence; and gave the plaintiffs additional time to amend their complaints
      to
      otherwise comply with the PUCO’s underlying order. Also, most
      complainants, along with the FirstEnergy companies, filed applications for
      rehearing with the PUCO over various rulings contained in the March 7, 2006
      order. On April 26, 2006, the PUCO granted rehearing to allow the insurance
      company claimants, as insurers, to prosecute their claims in their name so
      long
      as they also identify the underlying insured entities and the Ohio utilities
      that provide their service. The PUCO denied all other motions for rehearing.
      The
      plaintiffs in each case have since filed an amended complaint and the named
      FirstEnergy companies have answered and also have filed a motion to dismiss
      each
      action. These motions are pending. Additionally, on June 23, 2006, one of the
      insurance carrier complainants filed an appeal with the Ohio Supreme Court
      over
      the PUCO’s denial of motion for rehearing on the issue of the admissibility of
      the Task Force Report and the dismissal of FirstEnergy Corp. as a respondent.
      Briefing is expected to be completed on this appeal by mid-September. It is
      unknown when the Supreme Court will rule on the appeal. No estimate of potential
      liability is available for any of these cases.




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. FirstEnergy's motion to dismiss the matter was denied on June 2,
      2006. FirstEnergy has since filed an appeal, which is pending. A responsive
      pleading to this matter has been filed. Also, the complaint has been amended
      to
      include an additional party. No estimate of potential liability has been
      undertaken in this matter.


12




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




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





*Nuclear
      Plant
      Matters*




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




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




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




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




On September 28, 2005, the NRC sent a CAL to FENOC describing commitments
      that FENOC had made to improve the performance at the Perry 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.


13


*Other
      Legal
      Matters*




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




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




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




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. Both filings were
      consolidated for hearing and decision described above. An adverse ruling could
      negatively affect full recovery of transition charges by the utility. Hearings
      on the matter were held in August 2005. Initial briefs from all parties were
      filed on September 22, 2005 and reply briefs were filed on October 14,
      2005. On
      May 10,
      2006, the PUCO issued its Opinion and Order dismissing the City’s complaint and
      approving the related tariffs, thus affirming OE’s entitlement to recovery of
      its transition charges. The City of Huron
      filed an application for rehearing of the PUCO’s decision on June 9, 2006
      and OE filed a memorandum in opposition to that application on June 19,
      2006. The PUCO denied the City’s application for rehearing on June 28, 2006. The
      City of Huron has 60 days from the denial of rehearing to appeal the PUCO’s
      decision.




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


14


**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.





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




The EPACT provides for the creation of an ERO to establish and enforce
      reliability standards for the bulk power system, subject to FERC 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. The ERO filing was noticed on April 7, 2006 and comments and reply
      comments were filed in May, June and July 2006. On July 20, 2006, the FERC
      certified NERC as the ERO to implement the provisions of Section 215 of the
      Federal Power Act. The FERC directed NERC to make a compliance filing within
      ninety days addressing such issues as the regional delegation
      agreements.


On April 4, 2006, NERC also submitted a filing with the FERC seeking approval
      of
      mandatory reliability standards. These reliability standards are based, with
      some modifications, on the current NERC Version O reliability standards with
      some additional standards. The reliability standards filing was noticed by
      the
      FERC on April 18, 2006. In that notice, the FERC announced its intent to issue
      a
      Notice of Proposed Rulemaking on the proposed reliability standards at a future
      date. On May 11, 2006, the FERC staff released a preliminary assessment that
      cited many deficiencies in the proposed reliability standards. The NERC and
      industry participants filed comments in response to the Staff’s preliminary
      assessment. The FERC held a technical conference on the proposed reliability
      standards on July 6, 2006. The chairman has indicated that the FERC intends
      to
      act on the proposed reliability standards by issuing a NOPR in September of
      this
      year. Interested parties will be given the opportunity to comment on the NOPR.
      NERC has requested an effective date of January 1, 2007 for the proposed
      reliability standards.





15


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




On May 2, 2006, the NERC Board of Trustees adopted eight new cyber security
      standards that replaced interim standards put in place in the wake of the
      September 11, 2001 terrorist attacks, and thirteen additional reliability
      standards. The security standards became effective on June 1, 2006, and the
      remaining standards will become effective throughout 2006 and 2007. NERC intends
      to file the standards with the FERC and relevant Canadian authorities for
      approval.





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.





**OHIO**





On
      October 21, 2003
      the Ohio Companies filed their RSP case with the PUCO. On August 5, 2004, the
      Ohio Companies accepted the RSP as modified and approved by the PUCO in an
      August 4, 2004 Entry on Rehearing, subject to a CBP. The RSP was intended to
      establish generation service rates beginning January 1, 2006, in response to
      the
      PUCO’s concerns about price and supply uncertainty following the end of the Ohio
      Companies' transition plan market development period. In October 2004, the
      OCC
      and NOAC filed appeals with the Supreme Court of Ohio to overturn the original
      June 9, 2004 PUCO order in the proceeding as well as the associated entries
      on
      rehearing. On September 28, 2005, the Supreme Court of Ohio heard oral arguments
      on the appeals. On May 3, 2006, the Supreme Court of Ohio issued an opinion
      affirming the PUCO's order with respect to the approval of the rate
      stabilization charge, approval of the shopping credits, the granting of interest
      on shopping credit incentive deferral amounts, and approval of the Ohio
      Companies’ financial separation plan. It remanded one matter back to the PUCO
      for further consideration of the issue as to whether the RSP, as adopted by
      the
      PUCO, provided for sufficient means for customer participation in the
      competitive marketplace. On May 12, 2006, the Ohio Companies filed a Motion
      for
      Reconsideration with the Supreme Court of Ohio which was denied by the Court
      on
      June 21, 2006. The RSP contained a provision that permitted the Ohio Companies
      to withdraw and terminate the RSP in the event that the PUCO, or the Supreme
      Court of Ohio, rejected all or part of the RSP. In such event, the Ohio
      Companies have 30 days from the final order or decision to provide notice of
      termination. On July 20, 2006 the Ohio Companies filed with the PUCO a Request
      to Initiate a Proceeding on Remand. In their Request, the Ohio Companies
      provided notice of termination to those provisions of the RSP subject to
      termination, subject to being withdrawn, and also set forth a framework for
      addressing the Supreme Court of Ohio’s findings on customer participation,
      requesting the PUCO to initiate a proceeding to consider the Ohio Companies’
proposal. If the PUCO approves a resolution to the issues raised by the Supreme
      Court of Ohio that is acceptable to the Ohio Companies, the Ohio Companies’
termination will be withdrawn and considered to be null and void. Separately,
      the OCC and NOAC also submitted to the PUCO on July 20, 2006 a conceptual
      proposal dealing with the issue raised by the Supreme Court of Ohio. On July
      26,
      2006, the PUCO issued an Entry acknowledging the July 20, 2006 filings of the
      Ohio Companies and the OCC and NOAC, and giving the Ohio Companies 45 days
      to
      file a plan in a new docket to address the Court’s concern.




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





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


16





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





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





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




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





On December 30, 2004, the Ohio Companies filed with the PUCO two
      applications related to the recovery of transmission and ancillary service
      related costs. The first application sought recovery of these costs beginning
      January 1, 2006. The Ohio Companies requested that these costs be recovered
      through a rider that would be effective on January 1, 2006 and adjusted
      each July 1 thereafter. The parties reached a settlement agreement that was
      approved by the PUCO on August 31, 2005. The incremental transmission and
      ancillary service revenues recovered from January 1 through June 30,
      2006 were approximately $61 million. That amount included the recovery of a
      portion of the 2005 deferred MISO expenses as described below. On May 1,
      2006, the Ohio Companies filed a modification to the rider to determine revenues
      ($141 million) 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
      October 1, 2003 through December 31, 2005. On May 18, 2005, the
      PUCO granted the accounting authority for the Ohio Companies to defer
      incremental transmission and ancillary service-related charges incurred as
      a
      participant in MISO, but only for those costs incurred during the period
      December 30, 2004 through December 31, 2005. Permission to defer costs
      incurred prior to December 30, 2004 was denied. The PUCO also authorized
      the Ohio Companies to accrue carrying charges on the deferred balances. On
      August 31, 2005, the OCC appealed the PUCO's decision. On
      January 20,
      2006, the OCC sought rehearing of the PUCO’s approval of the recovery of
      deferred costs through the rider during the period January 1, 2006 through
      June 30, 2006. The PUCO denied the OCC's application on February 6,
      2006. On March 23, 2006, the OCC appealed the PUCO's order to the Ohio
      Supreme Court. On March 27, 2006, the OCC filed a motion to consolidate
      this appeal with the deferral appeals discussed above and to postpone oral
      arguments in the deferral appeal until after all briefs are filed in this most
      recent appeal of the rider recovery mechanism. On
      March 20, 2006,
      the Ohio Supreme Court, on its own motion, consolidated the OCC's appeal of
      the
      Ohio Companies' case with a similar case involving Dayton Power & Light
      Company. Oral arguments were heard on May 10, 2006. The Ohio Companies are
      unable to predict when a decision may be issued.


17





**PENNSYLVANIA**




A February 2002 Commonwealth Court of Pennsylvania decision affirmed the June
      2001 PPUC decision regarding approval of the FirstEnergy/GPU merger, remanded
      the issues of quantification and allocation of merger savings to the PPUC and
      denied Met-Ed and Penelec the rate relief initially approved in the PPUC
      decision. On October 2, 2003, the PPUC issued an order concluding that the
      Commonwealth Court reversed the PPUC’s June 2001 order in its entirety. In
      accordance with the PPUC's direction, Met-Ed and Penelec filed supplements
      to
      their tariffs that became effective in October 2003 and that reflected the
      CTC
      rates and shopping credits in effect prior to the June 2001
      order.




Met-Ed’s and Penelec’s combined portion of total net merger savings during 2001
      - 2004 is estimated to be approximately $51 million. A procedural schedule
      was established by the ALJ on January 17, 2006 and the companies filed
      initial testimony on March 1, 2006. On May 4, 2006, the PPUC
      consolidated this proceeding with the April 10, 2006 comprehensive rate
      filing proceeding discussed below. Met-Ed and Penelec are unable to predict
      the
      outcome of this matter.




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




As
      of June 30, 2006, Met-Ed's and Penelec's regulatory deferrals pursuant to the
      1998 Restructuring Settlement (including the Phase 2 Proceedings) and the
      FirstEnergy/GPU Merger Settlement Stipulation were $335 million and
      $57 million, respectively. Penelec's $57 million is subject to the
      pending resolution of taxable income issues associated with NUG trust fund
      proceeds. The PPUC is reviewing a January 2006 change in Met-Ed’s and Penelec’s
      NUG purchase power stranded cost accounting methodology. If the PPUC orders
      Met-Ed and Penelec to reverse the change in accounting methodology, this would
      result in a pre-tax loss of $10.3 million for Met-Ed.





On
      January 12,
      2005, Met-Ed and Penelec filed, before the PPUC, a request for deferral of
      transmission-related costs beginning January 1, 2005. The OCA, OSBA, OTS,
      MEIUG, PICA, Allegheny Electric Cooperative and Pennsylvania Rural Electric
      Association all intervened in the case. Met-Ed and Penelec sought to consolidate
      this proceeding (and modified their request to provide deferral of 2006
      transmission-related costs only) with the comprehensive rate filing they made
      on
      April 10, 2006 as described below. On May 4, 2006, the PPUC approved
      the modified request. Accordingly, Met-Ed and Penelec have deferred
      approximately $46 million and $12 million, respectively, representing
      transmission costs that were incurred from January 1, 2006 through June 30,
      2006. On June 5, 2006, the OCA filed before the Commonwealth Court a
      petition for review of the PPUC’s approval of the deferral. On July 12, 2006,
      the Commonwealth Court granted the PPUC’s motion to quash the OCA’s appeal. The
      ratemaking treatment of the deferrals will be determined in the comprehensive
      rate filing proceeding discussed further below.




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.


18




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





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





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


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


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


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





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




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




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 CBP as the amount of supply provided
      under the existing FES agreement is phased out in accordance with the
      April 7, 2006 Tolling Agreement described above. Met-Ed
      and Penelec
      also requested approval of the January 12, 2005 petition for the deferral
      of transmission-related costs discussed above, but only for those costs incurred
      during 2006. In this rate filing, Met-Ed and Penelec also requested recovery
      of
      annual transmission and related costs incurred on or after January 1, 2007,
      plus the amortized portion of 2006 costs over a ten-year period, along with
      applicable carrying charges, through an adjustable rider similar to that
      implemented in Ohio. Changes in the
      recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs
      are
      also included in the filing. The filing contemplates a reduction in distribution
      rates for Met-Ed of $37 million annually and an increase in distribution
      rates for Penelec of $20 million annually. The PPUC suspended the effective
      date (June 10, 2006) of these rate changes for seven months after the
      filing as permitted under Pennsylvania law. If the PPUC
      adopts
      the overall positions taken in the intervenors’ testimony as filed, this would
      have a material adverse effect on the financial statements of FirstEnergy,
      Met-Ed and Penelec.Hearings are scheduled for late August 2006 and a
      PPUC decision is expected early in the first quarter of 2007.


19




Under Pennsylvania's electric competition law, Penn is required to secure
      generation supply for customers who do not choose alternative suppliers for
      their electricity. On October 11, 2005, Penn filed a plan with the PPUC to
      secure electricity supply for its customers at set rates following the end
      of
      its transition period on December 31, 2006. Penn recommended that the RFP
      process cover the period January 1, 2007 through May 31, 2008. To the
      extent that an affiliate of Penn supplies a portion of the PLR load included
      in
      the RFP, authorization to make the affiliate sale must be obtained from the
      FERC. Hearings before the PPUC were held on January 10, 2006 with main
      briefs filed on January 27, 2006 and reply briefs filed on February 3,
      2006. On February 16, 2006, the ALJ issued a Recommended Decision to adopt
      Penn's RFP process with modifications. On April 20, 2006, the PPUC approved
      the
      Recommended Decision with additional modifications to use an RFP process to
      obtain Penn's power supply requirements after 2006 through two separate
      solicitations. An initial solicitation was held for Penn in May 2006 with all
      tranches fully subscribed. On June 2, 2006, the PPUC approved the bid results
      for the first solicitation. On July 18, 2006, the second PLR solicitation was
      held for Penn. The tranches for the Residential Group and Small Commercial
      Group
      were fully subscribed. However, supply was only acquired for three of the five
      tranches for the Large Commercial Group. On July 20, 2006, the PPUC approved
      the
      submissions for the second bid. A residual solicitation is scheduled to be
      held
      on August 15, 2006 for the two remaining Large Commercial Group tranches.
      Acceptance of the winning bids is subject to approval by the PPUC.




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





**NEW
      JERSEY**




JCP&L
      is permitted to defer for future collection from customers the amounts by which
      its costs of supplying BGS to non-shopping customers and costs incurred under
      NUG agreements exceed amounts collected through BGS and NUGC rates and market
      sales of NUG energy and capacity. As of June 30, 2006, the accumulated deferred
      cost balance totaled approximately $638 million. New Jersey law allows for
      securitization of JCP&L's deferred balance upon application by JCP&L and
      a determination by the NJBPU that the conditions of the New Jersey restructuring
      legislation are met. On February 14, 2003, JCP&L filed for approval to
      securitize the July 31, 2003 deferred balance. On June 8, 2006, the NJBPU
      approved JCP&L’s request to issue securitization bonds associated with BGS
      stranded cost deferrals. On August 4, 2006, JCP&L Transition Funding II, a
      wholly owned subsidiary of JCP&L, secured pricing on the issuance of $182
      million of transition bonds with a weighted average interest rate of
      5.5%.




On December 2, 2005, JCP&L filed its request for recovery of
      $165 million of actual above-market NUG costs incurred from August 1,
      2003 through October 31, 2005 and forecasted above-market NUG costs for
      November and December 2005. On February 23, 2006, JCP&L filed updated data
      reflecting actual amounts through December 31, 2005 of $154 million of
      costs incurred since July 31, 2003. On March 29, 2006, a pre-hearing
      conference was held with the presiding ALJ. 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 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 last of the quarterly reliability reports was submitted on June
      12, 2006. As of June 30, 2006, there were no performance penalties issued
      by the NJBPU.




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. On June 21, 2006,
      the NJBPU approved the continued use of a descending block auction for the
      Fixed
      Price Residential Class. A final decision as to the procurement method for
      the
      Commercial Industrial Energy Price Class is expected in October
      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.


20





On
      August 1,
      2005, the NJBPU established a proceeding to determine whether additional
      ratepayer protections are required at the state level in light of the repeal
      of
      PUHCA pursuant to the EPACT. An NJBPU proposed rulemaking to address the issues
      was published in the NJ Register on December 19, 2005. The proposal would
      prevent a holding company that owns a gas or electric public utility from
      investing more than 25% of the combined assets of its utility and
      utility-related subsidiaries into businesses unrelated to the utility industry.
      A public hearing was held on February 7, 2006 and comments were submitted
      to the NJBPU. 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. With the approval
      of the NJBPU Staff, the affected utilities jointly submitted an alternative
      proposal on June 1, 2006. Comments on the alternative proposal were submitted
      on
      June 15, 2006. JCP&L is unable to predict the outcome of this
      proceeding.




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





**FERC
      MATTERS**





On
      November 1, 2004,
      ATSI filed with the FERC a request to defer approximately $54 million of
      costs to be incurred from 2004 through 2007 in connection with ATSI’s VMEP,
      which represents ATSI’s adoption of newly identified industry “best practices”
for vegetation management. On March 4, 2005, the FERC approved ATSI’s
      request to defer the VMEP costs (approximately $33 million has been
      deferred as of June 30, 2006). On March 28, 2006, ATSI and MISO filed with
      the FERC a request to modify ATSI’s Attachment O formula rate to include
      revenue requirements associated with recovery of deferred VMEP costs over a
      five-year period. The requested effective date to begin recovery was
      June 1, 2006. Various parties filed comments responsive to the
      March 28, 2006 submission. The FERC conditionally approved the filing on
      May 22, 2006, subject to a compliance filing that ATSI made on June 13,
      2006. A request for rehearing of the FERC’s May 22, 2006 Order was filed by a
      party, which ATSI answered. On July 21, 2006, the FERC issued an order stating
      that it needs more time to consider the matter. In light of that order, there
      is
      no time period by which the FERC must act on the pending rehearing request.
      On
      July 14, 2006, the FERC accepted ATSI’s June 13, 2006 compliance filing. The
      estimated annual revenues to ATSI from the VMEP cost recovery is
      $12 million.




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




On November 18, 2004, the FERC issued an order eliminating the RTOR for
      transmission service between the MISO and PJM regions. The FERC also ordered
      the
      MISO, PJM and the transmission owners within MISO and PJM to submit compliance
      filings containing a SECA mechanism to recover lost RTOR revenues during a
      16-month transition period from load serving entities. The FERC issued orders
      in
      2005 setting the SECA for hearing. ATSI, JCP&L, Met-Ed, Penelec, and FES
      continue to be involved in the FERC hearings concerning the calculation and
      imposition of the SECA charges. The hearing was held in May 2006. Initial
      briefs were submitted on June 9, 2006, and reply briefs were filed on June
      27, 2006. The FERC has ordered the Presiding Judge to issue an initial decision
      by August 11, 2006.


21


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




On
      November 1, 2005, FES filed two power sales agreements for approval with
      the FERC. One power sales agreement provided for FES to provide the PLR
      requirements of the Ohio Companies at a price equal to the retail generation
      rates approved by the PUCO for a period of three years beginning January 1,
      2006. The Ohio Companies will be relieved of their obligation to obtain PLR
      power requirements from FES if the Ohio CBP results in a lower price for retail
      customers. A similar power sales agreement between FES and Penn permits Penn
      to
      obtain its PLR power requirements from FES at a fixed price equal to the retail
      generation price during 2006. 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 through two separate solicitations. An initial solicitation was
      held
      for Penn in May 2006 with all tranches fully subscribed. On June 2, 2006, the
      PPUC approved the bid results for the first solicitation. On July 18, 2006,
      the
      second PLR solicitation was held for Penn. The tranches for the Residential
      Group and Small Commercial Group were fully subscribed. However, supply was
      only
      acquired for three of the five tranches for the Large Commercial Group. On
      July
      20, 2006, the PPUC approved the submission for the second bid. A residual
      solicitation is scheduled to be held on August 15, 2006 for the two remaining
      Large Commercial Group tranches. Acceptance of the winning bids is subject
      to
      approval by the PPUC.




On December 29, 2005, the FERC issued an order setting the two power sales
      agreements for hearing. The order criticized the Ohio CBP, and required FES
      to
      submit additional evidence in support of the reasonableness of the prices
      charged in the power sales agreements. A pre-hearing conference was held on
      January 18, 2006 to determine the hearing schedule in this case. Under the
      procedural schedule approved in this case, FES expected an initial decision
      to
      be issued in late January 2007. However, on July 14, 2006, the Chief Judge
      granted the joint motion of FES and the Trial Staff to appoint a settlement
      judge in this proceeding. The procedural schedule has been suspended pending
      settlement discussions among the parties.





**12.
      - NEW
      ACCOUNTING STANDARDS AND INTERPRETATIONS**





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





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





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


22





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





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





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





**13.
      -
      SEGMENT INFORMATION**




FirstEnergy has two reportable segments: regulated services and power supply
      management services. The aggregate “Other” segments do not individually meet the
      criteria to be considered a reportable segment. The regulated services segment's
      operations include the regulated sale of electricity and distribution and
      transmission services by its eight utility subsidiaries in Ohio, Pennsylvania
      and New Jersey. The power supply management services segment primarily consists
      of the subsidiaries (FES, FGCO, NGC and FENOC) that sell electricity in
      deregulated markets and operate and now own the generation facilities of OE,
      CEI, TE and Penn resulting from the deregulation of the Companies' electric
      generation business. “Other” consists of telecommunications services, the
      recently sold MYR (a construction service company) and retail natural gas
      operations (see Note 4). The assets and revenues for the other business
      operations are below the quantifiable threshold for operating segments for
      separate disclosure as “reportable segments.”




The regulated services segment designs, constructs, operates and maintains
      FirstEnergy's regulated transmission and distribution systems. Its revenues
      are
      primarily derived from electricity delivery and transition cost recovery. Assets
      of the regulated services segment as of June 30, 2005 included generating units
      that were leased or whose output had been sold to the power supply management
      services segment. The regulated services segment’s 2005 internal revenues
      represented the rental revenues for the generating unit leases which ceased
      in
      the fourth quarter of 2005 as a result of the intra-system generation asset
      transfers (see Note 14).




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
      customers primarily in Ohio, Pennsylvania, Maryland 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 revised to conform to the
      current year business segment organization and operations and the
      reclassification of discontinued operations (see Note 4). Changes in the current
      year operations reporting reflected in the revised 2005 segment reporting
      primarily includes the transfer of retail transmission revenues and PJM/MISO
      transmission revenues and expenses associated with serving electricity load
      previously included in the regulated services segment to the power supply
      management services segment. In addition, as a result of the 2005 Ohio tax
      legislation reducing the effective state income tax rate, the calculated
      composite income tax rates used in the two reportable segments’ results for 2005
      and 2006 have been changed to 40% from the 41% previously reported in their
      2005
      segment results. The net amounts of the changes in the 2005 reportable segments'
      income taxes reclassifications have been correspondingly offset in the 2005
      "Reconciling Adjustments." FSG is being disclosed as a reportable segment due
      to
      its subsidiaries qualifying as held for sale. Interest expense on holding
      company debt and corporate support services revenues and expenses are included
      in "Reconciling Adjustments."


23








**Segment
                Financial Information**
            
            
            
            **Power****Supply****Regulated**
            
            **Management**
            
            **Facilities**
            
            
            
            **Reconciling****Three
                Months Ended**
            
            **Services**
            
            **Services**
            
            **Services**
            
            **Other**
            
            **Adjustments**
            
            **Consolidated*****(In
                millions)*****June
                30, 2006**External
                revenues
            
            $
            1,045
            
            $
            1,678
            
            $
            58
            
            $
            16
            
            $
            (11
            )
            $
            2,786Internal
                revenues
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Total
                revenues
            
            
            1,045
            
            
            1,678
            
            
            58
            
            
            16
            
            
            (11
            )
            
            2,786Depreciation
                and amortization
            
            
            228
            
            
            (36
            )
            
            -
            
            
            1
            
            
            5
            
            
            198Investment
                Income
            
            
            75
            
            
            2
            
            
            -
            
            
            1
            
            
            (47
            )
            
            31Net
                interest
                charges
            
            
            96
            
            
            54
            
            
            1
            
            
            1
            
            
            21
            
            
            173Income
                taxes
            
            
            155
            
            
            90
            
            
            1
            
            
            2
            
            
            (31
            )
            
            217Net
                income
            
            
            229
            
            
            135
            
            
            (11
            )
            
            (4
            )
            
            (45
            )
            
            304Total
                assets
            
            
            24,630
            
            
            6,740
            
            
            56
            
            
            299
            
            
            853
            
            
            32,578Total
                goodwill
            
            
            5,916
            
            
            24
            
            
            -
            
            
            -
            
            
            -
            
            
            5,940Property
                additions
            
            
            161
            
            
            103
            
            
            -
            
            
            1
            
            
            13
            
            
            278**June
                30, 2005**External
                revenues
            
            $
            1,226
            
            $
            1,416
            
            $
            59
            
            $
            135
            
            $
            7
            
            $
            2,843Internal
                revenues
            
            
            80
            
            
            -
            
            
            -
            
            
            -
            
            
            (80
            )
            
            -Total
                revenues
            
            
            1,306
            
            
            1,416
            
            
            59
            
            
            135
            
            
            (73
            )
            
            2,843Depreciation
                and amortization
            
            
            344
            
            
            (16
            )
            
            -
            
            
            -
            
            
            7
            
            
            335Investment
                income
            
            
            47
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            47Net
                interest
                charges
            
            
            99
            
            
            9
            
            
            -
            
            
            2
            
            
            51
            
            
            161Income
                taxes
            
            
            193
            
            
            (5
            )
            
            5
            
            
            1
            
            
            47
            
            
            241Income
                before
                discontinued operations
            
            
            288
            
            
            (5
            )
            
            (2
            )
            
            6
            
            
            (108
            )
            
            179Discontinued
                operations
            
            
            -
            
            
            -
            
            
            -
            
            
            (1
            )
            
            -
            
            
            (1
            )Net
                income
            
            
            288
            
            
            (5
            )
            
            (2
            )
            
            5
            
            
            (108
            )
            
            178Total
                assets
            
            
            28,454
            
            
            1,601
            
            
            78
            
            
            512
            
            
            566
            
            
            31,211Total
                goodwill
            
            
            5,946
            
            
            24
            
            
            -
            
            
            63
            
            
            -
            
            
            6,033Property
                additions
            
            
            158
            
            
            66
            
            
            -
            
            
            2
            
            
            7
            
            
            233





**Six
                Months Ended****June
                30, 2006**External
                revenues
            
            $
            2,128
            
            $
            3,297
            
            $
            104
            
            $
            136
            
            $
            (34
            )
            $
            5,631Internal
                revenues
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Total
                revenues
            
            
            2,128
            
            
            3,297
            
            
            104
            
            
            136
            
            
            (34
            )
            
            5,631Depreciation
                and amortization
            
            
            486
            
            
            (11
            )
            
            -
            
            
            2
            
            
            10
            
            
            487Investment
                Income
            
            
            137
            
            
            17
            
            
            -
            
            
            1
            
            
            (81
            )
            
            74Net
                interest
                charges
            
            
            189
            
            
            103
            
            
            1
            
            
            2
            
            
            38
            
            
            333Income
                taxes
            
            
            299
            
            
            117
            
            
            1
            
            
            (5
            )
            
            (61
            )
            
            351Net
                income
            
            
            440
            
            
            175
            
            
            (12
            )
            
            11
            
            
            (89
            )
            
            525Total
                assets
            
            
            24,630
            
            
            6,740
            
            
            56
            
            
            299
            
            
            853
            
            
            32,578Total
                goodwill
            
            
            5,916
            
            
            24
            
            
            -
            
            
            -
            
            
            -
            
            
            5,940Property
                additions
            
            
            356
            
            
            347
            
            
            -
            
            
            2
            
            
            20
            
            
            725**June
                30, 2005**External
                revenues
            
            $
            2,442
            
            $
            2,793
            
            $
            102
            
            $
            247
            
            $
            9
            
            $
            5,593Internal
                revenues
            
            
            158
            
            
            -
            
            
            -
            
            
            -
            
            
            (158
            )
            
            -Total
                revenues
            
            
            2,600
            
            
            2,793
            
            
            102
            
            
            247
            
            
            (149
            )
            
            5,593Depreciation
                and amortization
            
            
            718
            
            
            (3
            )
            
            -
            
            
            1
            
            
            13
            
            
            729Investment
                income
            
            
            88
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            88Net
                interest
                charges
            
            
            197
            
            
            19
            
            
            -
            
            
            3
            
            
            113
            
            
            332Income
                taxes
            
            
            350
            
            
            (35
            )
            
            2
            
            
            11
            
            
            34
            
            
            362Income
                before
                discontinued operations
            
            
            524
            
            
            (51
            )
            
            (4
            )
            
            11
            
            
            (160
            )
            
            320Discontinued
                operations
            
            
            -
            
            
            -
            
            
            13
            
            
            5
            
            
            -
            
            
            18Net
                income
            
            
            524
            
            
            (51
            )
            
            9
            
            
            16
            
            
            (160
            )
            
            338Total
                assets
            
            
            28,454
            
            
            1,601
            
            
            78
            
            
            512
            
            
            566
            
            
            31,211Total
                goodwill
            
            
            5,946
            
            
            24
            
            
            -
            
            
            63
            
            
            -
            
            
            6,033Property
                additions
            
            
            299
            
            
            147
            
            
            1
            
            
            4
            
            
            11
            
            
            462




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.


24





**14.
      -
      FIRSTENERGY INTRA-SYSTEM GENERATION ASSET TRANSFERS**




On May 13, 2005, Penn, and on May 18, 2005, the Ohio Companies,
      entered into certain agreements implementing a series of intra-system generation
      asset transfers that were completed in the fourth quarter of 2005. The asset
      transfers resulted in the respective undivided ownership interests of the Ohio
      Companies and Penn in FirstEnergy’s nuclear and non-nuclear generation assets
      being owned by NGC and FGCO, respectively. The generating plant interests
      transferred do not include leasehold interests of CEI, TE and OE in certain
      of
      the plants that are currently subject to sale and leaseback arrangements with
      non-affiliates.




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




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




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




**15.
      -
      JCP&L RESTATEMENT**





JCP&L's
      earnings
      for the three months and six months ended June 30, 2005 have been restated
      to
      reflect the results of a tax audit by the State of New Jersey, in which
      JCP&L became aware that the New Jersey Transitional Energy Facilities
      Assessment (TEFA) is not an allowable deduction for state income tax purposes.
      JCP&L had incorrectly claimed a state income tax deduction for TEFA payments
      and as a result, income taxes and interest expense were understated by
      $0.4 million and $0.6 million, respectively, in the second quarter of 2005
      and understated by $0.9 million and $1.2 million, respectively, in the
      first six months of 2005. The effects of these adjustments on JCP&L's
      Consolidated Statements of Income for the three months and six months ended
      June
      30, 2005 are as follows:





**Three
                Months**
            
            **Six
                Months****As
                Previously**
            
            
            **As**
            
            **As
                Previously**
            
            **As****Reported**
            
            
            **Restated**
            
            **Reported**
            
            **Restated*****(In
                millions)***Operating
                Revenues
            $
            595.3
            
            $
            595.3
            
            $
            1,124.4
            
            $
            1,124.4Operating
                Expenses andTaxes
            
            521.2
            
            
            521.6
            
            
            1,015.9
            
            
            1,016.8Operating
                Income
            
            74.1
            
            
            73.7
            
            
            108.5
            
            
            107.6Other
                Income
            
            0.3
            
            
            0.3
            
            
            0.3
            
            
            0.3Net
                Interest
                Charges
            
            19.1
            
            
            19.7
            
            
            39.0
            
            
            40.2Net
                Income
            $
            55.3
            
            $
            54.3
            
            $
            69.8
            
            $
            67.7Earnings
                Applicableto
                Common
                Stock
            $
            55.2
            
            $
            54.2
            
            $
            69.6
            
            $
            67.5





These
      adjustments
      were not material to FirstEnergy's consolidated financial statements, nor
      JCP&L's Consolidated Balance Sheets or Consolidated Statements of Cash
      Flows.





**16.
      -
      SUBSEQUENT EVENTS**





**Pennsylvania
      Law Change**





On
      July 12, 2006,
      the Governor of Pennsylvania signed House Bill 859, which increases the net
      operating loss deduction allowed for the corporate net income tax from
      $2 million to $3 million, or the greater of 12.5% of taxable income.
      As a result, FirstEnergy expects to recognize a net operating loss benefit
      of
      $2.2 million (net of federal tax benefit) in the third quarter of
      2006.


25





**New
      Jersey
      Law Change**





On
      July 8, 2006, the
      Governor of New Jersey signed tax legislation that increased the current New
      Jersey Corporate Business tax by an additional 4% surtax, which increases the
      effective tax rate from 9% to 9.36%. This increase applies to JCP&L’s 2006
      through 2008 tax years and is not expected to have a material impact on
      FirstEnergy’s or JCP&L’s results of operations.





26





**FIRSTENERGY
                  CORP.****CONSOLIDATED
                  STATEMENTS OF INCOME****(Unaudited)****Three
                  Months Ended**
              
              **Six
                  Months Ended****June
                  30,**
              
              **June
                  30,****2006**
              
              **2005**
              
              **2006**
              
              **2005*****(In
                  millions, except per share amounts)*****REVENUES:**Electric
                  utilities
              
              $
              2,341
              
              $
              2,283
              
              $
              4,681
              
              $
              4,550Unregulated
                  businesses
              
              
              445
              
              
              560
              
              
              950
              
              
              1,043Total
                  revenues
              
              
              2,786
              
              
              2,843
              
              
              5,631
              
              
              5,593**EXPENSES:**Fuel
                  and
                  purchased power
              
              
              992
              
              
              933
              
              
              1,990
              
              
              1,828Other
                  operating expenses
              
              
              760
              
              
              873
              
              
              1,653
              
              
              1,757Provision
                  for
                  depreciation
              
              
              144
              
              
              149
              
              
              292
              
              
              292Amortization
                  of regulatory assets
              
              
              199
              
              
              306
              
              
              421
              
              
              617Deferral
                  of
                  new regulatory assets
              
              
              (145
              )
              
              (120
              )
              
              (226
              )
              
              (180
              )General
                  taxes
              
              
              173
              
              
              168
              
              
              366
              
              
              353Total
                  expenses
              
              
              2,123
              
              
              2,309
              
              
              4,496
              
              
              4,667**OPERATING
                  INCOME**
              
              
              663
              
              
              534
              
              
              1,135
              
              
              926**OTHER
                  INCOME (EXPENSE):**Investment
                  income
              
              
              31
              
              
              47
              
              
              74
              
              
              88Interest
                  expense
              
              
              (178
              )
              
              (162
              )
              
              (343
              )
              
              (326
              )Capitalized
                  interest
              
              
              7
              
              
              5
              
              
              14
              
              
              4Subsidiaries’
                  preferred stock dividends
              
              
              (2
              )
              
              (4
              )
              
              (4
              )
              
              (10
              )Net
                  interest
                  charges
              
              
              (142
              )
              
              (114
              )
              
              (259
              )
              
              (244
              )**INCOME
                  TAXES**
              
              
              217
              
              
              241
              
              
              351
              
              
              362**INCOME
                  BEFORE DISCONTINUED OPERATIONS**
              
              
              304
              
              
              179
              
              
              525
              
              
              320Discontinued
                  operations (net of income tax benefits of$1
                  million and
                  $9 million in the three months andsix
                  months
                  ended June 30, 2005, respectively) (Note 4)
              
              
              -
              
              
              (1
              )
              
              -
              
              
              18**NET
                  INCOME**
              
              $
              304
              
              $
              178
              
              $
              525
              
              $
              338**BASIC
                  EARNINGS PER SHARE OF COMMON STOCK:**Earnings
                  before discontinued operations (Note 2)
              
              $
              0.92
              
              $
              0.54
              
              $
              1.59
              
              $
              0.98Discontinued
                  operations (Note 4)
              
              
              -
              
              
              -
              
              
              -
              
              
              0.05Net
                  earnings
                  per basic share
              
              $
              0.92
              
              $
              0.54
              
              $
              1.59
              
              $
              1.03**WEIGHTED
                  AVERAGE NUMBER OF BASIC SHARES****OUTSTANDING**
              
              
              328
              
              
              328
              
              
              328
              
              
              328**DILUTED
                  EARNINGS PER SHARE OF COMMON STOCK:**Earnings
                  before discontinued operations (Note 2)
              
              $
              0.91
              
              $
              0.54
              
              $
              1.58
              
              $
              0.97Discontinued
                  operations (Note 4)
              
              
              -
              
              
              -
              
              
              -
              
              
              0.05Net
                  earnings
                  per diluted share
              
              $
              0.91
              
              $
              0.54
              
              $
              1.58
              
              $
              1.02**WEIGHTED
                  AVERAGE NUMBER OF DILUTED SHARES****OUTSTANDING**
              
              
              330
              
              
              330
              
              
              330
              
              
              330**DIVIDENDS
                  DECLARED PER SHARE OF COMMON STOCK**
              
              $
              0.45
              
              $
              0.4125
              
              $
              0.90
              
              $
              0.825The
                  preceding
                  Notes to Consolidated Financial Statements as they relate to FirstEnergy
                  Corp. are an integral part of these statements.
   27
  **FIRSTENERGY
                    CORP.****CONSOLIDATED
                    STATEMENTS OF COMPREHENSIVE INCOME****(Unaudited)****Three
                    Months Ended**
                
                **Six
                    Months Ended****June
                    30,**
                
                **June
                    30,****2006**
                
                **2005**
                
                **2006**
                
                **2005*****(In
                    millions)*****NET
                    INCOME**
                
                $
                304
                
                $
                178
                
                $
                525
                
                $
                338**OTHER
                    COMPREHENSIVE INCOME (LOSS):**Unrealized
                    gain (loss) on derivative hedges
                
                
                36
                
                
                (6
                )
                
                73
                
                
                1Unrealized
                    gain (loss) on available for sale securities
                
                
                (24
                )
                
                (16
                )
                
                13
                
                
                (24
                )Other
                    comprehensive income (loss)
                
                
                12
                
                
                (22
                )
                
                86
                
                
                (23
                )Income
                    tax
                    expense (benefit) related to othercomprehensive
                    income
                
                
                4
                
                
                (6
                )
                
                31
                
                
                (6
                )Other
                    comprehensive income (loss), net of tax
                
                
                8
                
                
                (16
                )
                
                55
                
                
                (17
                )**COMPREHENSIVE
                    INCOME**
                
                $
                312
                
                $
                162
                
                $
                580
                
                $
                321The
                    preceding
                    Notes to Consolidated Financial Statements as they relate to
                    FirstEnergy
                    Corp. are an integral part of these
                    statements.
   
    28
  **FIRSTENERGY
                    CORP.****CONSOLIDATED
                    BALANCE SHEETS****(Unaudited)****June
                    30,**
                
                **December
                    31,****2006**
                
                **2005*****(In
                    millions)*****ASSETS****CURRENT
                    ASSETS:**Cash
                    and cash
                    equivalents
                $
                583
                
                $
                64Receivables
                    -Customers
                    (less accumulated provisions of $36 million and$38
                    million,
                    respectively, for uncollectible accounts)
                
                1,173
                
                
                1,293Other
                    (less
                    accumulated provisions of $27 millionfor
                    uncollectible accounts in both periods)
                
                173
                
                
                205Materials
                    and
                    supplies, at average cost
                
                629
                
                
                518Prepayments
                    and other
                
                254
                
                
                2372,812
                
                
                2,317**PROPERTY,
                    PLANT AND EQUIPMENT:**In
                    service
                
                23,661
                
                
                22,893Less
                    -
                    Accumulated provision for depreciation
                
                9,883
                
                
                9,79213,778
                
                
                13,101Construction
                    work in progress
                
                642
                
                
                89714,420
                
                
                13,998**INVESTMENTS:**Nuclear
                    plant
                    decommissioning trusts
                
                1,796
                
                
                1,752Investments
                    in
                    lease obligation bonds
                
                830
                
                
                890Other
                
                
                745
                
                
                7093,371
                
                
                3,351**DEFERRED
                    CHARGES AND OTHER ASSETS:**Goodwill
                
                5,940
                
                
                6,010Regulatory
                    assets
                
                4,396
                
                
                4,486Prepaid
                    pension costs
                
                1,013
                
                
                1,023Other
                
                
                626
                
                
                65611,975
                
                
                12,175$
                32,578
                
                $
                31,841**LIABILITIES
                    AND CAPITALIZATION****CURRENT
                    LIABILITIES:**Currently
                    payable long-term debt
                $
                2,004
                
                $
                2,043Short-term
                    borrowings
                
                1,101
                
                
                731Accounts
                    payable
                
                682
                
                
                727Accrued
                    taxes
                
                750
                
                
                800Other
                
                
                852
                
                
                1,1525,389
                
                
                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
                
                7,052
                
                
                7,043Accumulated
                    other comprehensive income (loss)
                
                35
                
                
                (20)Retained
                    earnings
                
                2,385
                
                
                2,159Unallocated
                    employee stock ownership plan common stock -960,651
                    and
                    1,444,796 shares, respectively
                
                (17)
                
                
                (27)Total
                    common
                    stockholders' equity
                
                9,488
                
                
                9,188Preferred
                    stock of consolidated subsidiaries
                
                154
                
                
                184Long-term
                    debt
                    and other long-term obligations
                
                8,729
                
                
                8,15518,371
                
                
                17,527**NONCURRENT
                    LIABILITIES:**Accumulated
                    deferred income taxes
                
                2,792
                
                
                2,726Asset
                    retirement obligations
                
                1,160
                
                
                1,126Power
                    purchase
                    contract loss liability
                
                1,123
                
                
                1,226Retirement
                    benefits
                
                1,355
                
                
                1,316Lease
                    market
                    valuation liability
                
                809
                
                
                851Other
                
                
                1,579
                
                
                1,6168,818
                
                
                8,861**COMMITMENTS,
                    GUARANTEES AND CONTINGENCIES (Note 10)**$
                32,578
                
                $
                31,841The
                    preceding
                    Notes to Consolidated Financial Statements as they relate to
                    FirstEnergy
                    Corp. are an integral part of thesebalance
                    sheets.
   29
  **FIRSTENERGY
                    CORP.****CONSOLIDATED
                    STATEMENTS OF CASH FLOWS****(Unaudited)****Six
                    Months Ended****June
                    30,****2006**
                
                **2005*****(In
                    millions)*****CASH
                    FLOWS FROM OPERATING ACTIVITIES:**Net
                    income
                $
                525
                
                $
                338Adjustments
                    to
                    reconcile net income to net cash from operating activities
                    -Provision
                    for
                    depreciation
                
                292
                
                
                292Amortization
                    of regulatory assets
                
                421
                
                
                617Deferral
                    of
                    new regulatory assets
                
                (226
                )
                
                (180
                )Nuclear
                    fuel
                    and lease amortization
                
                30
                
                
                38Deferred
                    purchased power and other costs
                
                (239
                )
                
                (210
                )Deferred
                    income taxes and investment tax credits, net
                
                32
                
                
                62Deferred
                    rents
                    and lease market valuation liability
                
                (105
                )
                
                (101
                )Accrued
                    compensation and retirement benefits
                
                33
                
                
                11Commodity
                    derivative transactions, net
                
                25
                
                
                (6
                )Income
                    from
                    discontinued operations
                
                -
                
                
                (18
                )Cash
                    collateral
                
                (55
                )
                
                22Decrease
                    (increase) in operating assets -Receivables
                
                83
                
                
                (135
                )Materials
                    and
                    supplies
                
                (71
                )
                
                (52
                )Prepayments
                    and other current assets
                
                (81
                )
                
                (159
                )Increase
                    (decrease) in operating liabilities -Accounts
                    payable
                
                (40
                )
                
                104Accrued
                    taxes
                
                (45
                )
                
                39Accrued
                    interest
                
                -
                
                
                (4
                )Electric
                    service prepayment programs
                
                (29
                )
                
                226Other
                
                1
                
                
                37Net
                    cash
                    provided from operating activities
                
                551
                
                
                921**CASH
                    FLOWS FROM FINANCING ACTIVITIES:**New
                    Financing
                    -Long-term
                    debt
                
                1,053
                
                
                245Short-term
                    borrowings, net
                
                371
                
                
                386Redemptions
                    and Repayments -Preferred
                    stock
                
                (30
                )
                
                (140
                )Long-term
                    debt
                
                (487
                )
                
                (689
                )Net
                    controlled
                    disbursement activity
                
                5
                
                
                -Common
                    stock
                    dividend payments
                
                (296
                )
                
                (270
                )Net
                    cash
                    provided from (used for) financing activities
                
                616
                
                
                (468
                )**CASH
                    FLOWS FROM INVESTING ACTIVITIES:**Property
                    additions
                
                (725
                )
                
                (462
                )Proceeds
                    from
                    asset sales
                
                59
                
                
                61Proceeds
                    from
                    nuclear decommissioning trust fund sales
                
                925
                
                
                608Investments
                    in
                    nuclear decommissioning trust funds
                
                (932
                )
                
                (659
                )Cash
                    investments
                
                40
                
                
                35Other
                
                (15
                )
                
                (39
                )Net
                    cash used
                    for investing activities
                
                (648
                )
                
                (456
                )Net
                    increase
                    (decrease) in cash and cash equivalents
                
                519
                
                
                (3
                )Cash
                    and cash
                    equivalents at beginning of period
                
                64
                
                
                53Cash
                    and cash
                    equivalents at end of period
                $
                583
                
                $
                50The
                    preceding
                    Notes to Consolidated Financial Statements as they relate to
                    FirstEnergy
                    Corp. are an integral part ofthese
                    statements.






30










***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 June 30, 2006, and the related consolidated statements of
      income and comprehensive income for each of the three-month and six-month
      periods ended June 30, 2006 and 2005 and the consolidated statement of cash
      flows for the six-month period ended June 30, 2006 and 2005. These interim
      financial statements are the responsibility of the Company’s
      management.





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





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





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














PricewaterhouseCoopers
      LLP


Cleveland,
      Ohio


August
      4,
      2006








31


**FIRSTENERGY
      CORP.**





**MANAGEMENT’S
      DISCUSSION AND ANALYSIS OF**


**RESULTS
      OF
      OPERATIONS AND FINANCIAL CONDITION**








**EXECUTIVE
      SUMMARY**





Net
      income in the
      second quarter of 2006 was $304 million, or basic earnings of $0.92 per share
      of
      common stock ($0.91 diluted), compared with net income of $178 million, or
      basic
      and diluted earnings of $0.54 per share of common stock in the second quarter
      of
      2005. FirstEnergy’s earnings increase was driven primarily by increased electric
      sales revenues, reduced nuclear operating expenses, cost deferrals authorized
      by
      the PUCO and PPUC, and reduced transition cost amortization for the Ohio
      Companies. Earnings in the
      second quarter and the first six months of 2005 were reduced by $0.22 per share
      of common stock due to additional income tax expense of $71 million from
      the enactment of tax legislation in Ohio. Net income in the second quarter
      and
      the first six months of 2006 reflected net after-tax charges associated with
      the
      sale and impairment of non-core assets of $9 million (or $0.03 per share)
      and $11 million (or $0.03 per share), respectively. The following Non-GAAP
      Reconciliation displays the unusual items resulting in the difference between
      GAAP and non-GAAP earnings.





**Reconciliation
                of non-GAAP to GAAP**
            
            **2006**
            
            **2005****After-tax**
            
            **Basic**
            
            **After-tax**
            
            **Basic****Amount**
            
            **Earnings**
            
            **Amount**
            
            **Earnings****Three
                Months Ended June 30,**
            
            **(Millions)**
            
            **Per
                Share**
            
            **(Millions)**
            
            **Per
                Share**Earnings
                Before Unusual Items (Non-GAAP)
            
            $
            313
            
            $
            0.95
            
            $
            233
            
            $
            0.71Unusual
                Items:Non-core
                asset
                sales/impairments
            
            
            (9
            )
            
            (0.03
            )
            
            -
            
            
            -New
                regulatory
                assets - JCP&L rate settlement
            
            
            -
            
            
            -
            
            
            16
            
            
            0.05Ohio
                tax
                write-off
            
            
            -
            
            
            -
            
            
            (71
            )
            
            (0.22
            )Net
                Income
                (GAAP)
            
            $
            304
            
            $
            0.92
            
            $
            178
            
            $
            0.54**Six
                Months Ended June 30,**Earnings
                Before Unusual Items (Non-GAAP)
            
            $
            536
            
            $
            1.62
            
            $
            388
            
            $
            1.18Unusual
                Items:Non-core
                asset
                sales/impairments
            
            
            (11
            )
            
            (0.03
            )
            
            22
            
            
            0.07Sammis
                plant
                New Source Review settlement
            
            
            -
            
            
            -
            
            
            (14
            )
            
            (0.04
            )Davis-Besse
                NRC fine
            
            
            -
            
            
            -
            
            
            (3
            )
            
            (0.01
            )New
                regulatory
                assets - JCP&L rate settlement
            
            
            -
            
            
            -
            
            
            16
            
            
            0.05Ohio
                tax
                write-off
            
            
            -
            
            
            -
            
            
            (71
            )
            
            (0.22
            )Net
                Income
                (GAAP)
            
            $
            525
            
            $
            1.59
            
            $
            338
            
            $
            1.03





The
      Non-GAAP measure
      above, earnings before unusual items, is not calculated in accordance with
      GAAP
      because it excludes the impact of "unusual items." Unusual items reflect the
      impact on earnings of events that are not routine or for which FirstEnergy
      believes the financial impact will disappear or become immaterial within a
      near-term finite period. By removing the earnings effect of such issues that
      have been resolved or are expected to be resolved over the near term, management
      and investors can better measure FirstEnergy’s business and earnings potential.
      In particular, the non-core asset sales item refers to a finite set of
      energy-related assets that had been previously disclosed as held for sale,
      a
      substantial portion of which has already been sold. Similarly, the NRC fine
      in
      2005 and further litigation settlements similar to the class action settlements
      in 2005 are not reasonably expected over the near term. Furthermore, FirstEnergy
      believes presenting normalized earnings calculated in this manner provides
      useful information to investors in evaluating the ongoing results of
      FirstEnergy’s businesses over the longer term and assists investors in comparing
      FirstEnergy’s operating performance to the operating performance of others in
      the energy sector.





Total
      electric
      generation sales were up by 3.9% over last year’s second quarter. For the six
      months ended June 30, 2006, electric generation sales rose 3.0% compared to
      the
      same period last year. The increase for both periods was primarily due to the
      return of customers to the Ohio Companies from third-party suppliers that exited
      the Ohio marketplace. Electric distribution deliveries were down 1.8% and 2.2%
      for the quarter and year-to-date periods ending June 30, reflecting milder
      weather conditions in 2006.





FirstEnergy's
      generating fleet produced a second quarter record 20.3 billion KWH during
      the second quarter of 2006 compared to 19.1 billion KWH in the second
      quarter of 2005. FirstEnergy's non-nuclear fleet produced a record
      13.4 billion KWH, while its nuclear facilities produced 6.9 billion
      KWH.


32




Ohio Supreme Court Decision - On May 3, 2006, the Ohio Supreme Court affirmed,
      in all but one aspect, the provisions of FirstEnergy's RSP for its Ohio
      customers. An issue related to customer pricing options was remanded to the
      PUCO
      for further consideration. The Court found that FirstEnergy must provide an
      alternative market-based offering to customers in addition to that which they
      already have through their rate stabilization price, even if the alternative
      is
      higher than that offered through the RSP. On July 20, 2006, FirstEnergy filed
      a
      notice with the PUCO to address this issue through a proposed RFP program under
      which Ohio customers would have the opportunity to switch to alternative
      generation suppliers at prices established through the RFP program. FirstEnergy
      also provided notice of potential termination of certain portions of the RSP
      in
      the event that the issue is not resolved within a reasonable time frame or
      if
      modifications to the RSP are not acceptable. On July 26, 2006, the PUCO directed
      FirstEnergy to file within 45 days its plan to address the Court’s
      concern.





Pennsylvania
      Rate
      Matters - On May 31, 2006, the ALJ in the Met-Ed and Penelec rate transition
      plan filing established a procedural schedule with a goal of reaching a
      recommended decision in this proceeding by November 8, 2006. In accordance
      with this schedule, intervening parties submitted their written testimony by
      July 10, 2006. Ten public input hearings were held in various locations
      throughout the Met-Ed and Penelec service areas between June 20, 2006 and
      July 20, 2006.





Met-Ed
      and Penelec
      Transmission Charges - On May 4, 2006, the PPUC granted authority for Met-Ed
      and
      Penelec to defer, for accounting and financial reporting purposes, certain
      incremental transmission charges during 2006. The PPUC order allows Met-Ed
      and
      Penelec to defer, commencing January 1, 2006, the costs that are incremental
      to
      the levels currently reflected in the transmission component of Met-Ed’s and
      Penelec’s base rate tariffs. Recovery of the deferred costs will be considered
      in their pending comprehensive rate transition plan filing.




Penn RFP - On June 2, 2006, the PPUC approved the bid results for the first
      bid.
      On July 18, 2006, the second PLR bid process was held for Penn. On July 20,
      2006, the PPUC approved the submissions for the second bid. As a result of
      bids
      one and two, supply has been successfully acquired for all seven tranches of
      the
      Residential Group and all six of the Small Commercial Group. However, supply
      has
      only been acquired for three of the five tranches for the Large Commercial
      Group. Therefore, a residual third bid is scheduled to be held on August 15,
      2006 for the two remaining Large Commercial Group tranches.




Environmental
      Update - I n
      June 2006,
      FirstEnergy finalized its air quality compliance strategy for 2006 through
      2011.
      The program, which is expected to cost approximately $1.7 billion with the
      majority of those expenditures occurring between 2007 and 2009, is consistent
      with previous estimates and assumptions reflected in FirstEnergy’s long-term
      financial planning for air and water quality and other environmental
      matters.




Share Repurchase Program - On
      June 20, 2006,
      FirstEnergy's Board of Directors authorized a share repurchase program for
      up to
      12 million shares of common stock. At management’s discretion, shares may
      be acquired on the open market or through privately negotiated transactions,
      subject to market conditions and other factors. The Board’s authorization of the
      repurchase program does not require FirstEnergy to purchase any shares and
      the
      program may be terminated at any time. The 12 million shares represent 3.6%
      of the approximately 330 million shares of common stock currently
      outstanding.




OE Senior Notes Offering - On
      June 26, 2006, OE
      issued $600 million of unsecured senior notes, comprised of $250 million due
      2016 and $350 million due 2036. Proceeds from these offerings were used in
      July
      2006 to repurchase $500 million of OE’s common stock from FirstEnergy, to redeem
      $61 million of OE’s preferred stock and to reduce short-term debt. FirstEnergy
      primarily used the proceeds to redeem, on July 31, 2006, $400 million
      principal amount of its $1 billion, 5.5% Notes, Series A, in advance of the
      November 15, 2006 maturity date. This represents an important part of
      FirstEnergy’s 2006 financing strategy to obtain additional financing flexibility
      at the holding company level and to capitalize its regulated utilities more
      appropriately from a regulatory context.




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




JCP&L
      Securitization - On June 8, 2006, the NJBPU approved JCP&L's request to
      issue securitization bonds associated with BGS stranded cost deferrals. On
      August 4, 2006, JCP&L Transition Funding II, a wholly owned subsidiary of
      JCP&L, secured pricing on the issuance of $182 million of transition bonds
      with a weighted average interest rate of 5.5%.




New
      Coal Supply Agreement -
      On June 22, 2006,
      FGCO entered into a new coal supply agreement with CONSOL Energy, Inc. under
      which CONSOL will supply a total of more than 128 million tons of high-Btu
      coal
      to FirstEnergy for a 20-year period beginning in 2009. The new agreement
      replaces an existing coal supply agreement that took effect in January 2003
      and
      ran through 2020. Under the new agreement, CONSOL will increase its coal
      shipments by approximately 2 million tons per year.


33




Ratified Contract Agreements - On May 11, 2006, employees represented by Local
      270 of the Utility Workers Union of America (UWUA) voted to ratify a five-year
      contract agreement. UWUA Local 270 represents approximately 1,075 linemen,
      substation electricians, meter readers, and support personnel in the greater
      Cleveland area. On May 26, 2006, employees of Penelec represented by the
      International Brotherhood of Electrical Workers (IBEW) Local 459 ratified a
      three-year collective bargaining agreement. IBEW Local 459 includes 482 linemen,
      substation electricians, meter readers and support personnel.





**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 where 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 customers primarily in Ohio, Pennsylvania, Maryland 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.

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**




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




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




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




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


34





**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 June 30,**
            
            **Six
                Months Ended June 30,****Increase**
            
            
            
            **Increase****2006**
            
            **2005**
            
            **(Decrease)**
            
            **2006**
            
            **2005**
            
            **(Decrease)*****(In
                millions, except per share amounts)*****Net
                Income (Loss)****By
                Business Segment:**Regulated
                Services
            
            
            
            
            $
            229
            
            $
            288
            
            $
            (59
            )
            $
            440
            
            $
            524
            
            $
            (84
            )Power
                supply
                management services
            
            
            
            
            
            135
            
            
            (5
            )
            
            140
            
            
            175
            
            
            (51
            )
            
            226Other
                and
                reconciling adjustments*
            
            
            
            
            
            (60
            )
            
            (105
            )
            
            45
            
            
            (90
            )
            
            (135
            )
            
            45Total
            
            
            
            
            $
            304
            
            $
            178
            
            $
            126
            
            $
            525
            
            $
            338
            
            $
            187**Basic
                Earnings Per Share:**Income
                before
                discontinued operations
            
            
            
            
            $
            0.92
            
            $
            0.54
            
            $
            0.38
            
            $
            1.59
            
            $
            0.98
            
            $
            0.61Discontinued
                operations
            
            
            
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            0.05
            
            
            (0.05
            )Net
                earnings
                per basic share
            
            
            
            
            $
            0.92
            
            $
            0.54
            
            $
            0.38
            
            $
            1.59
            
            $
            1.03
            
            $
            0.56**Diluted
                Earnings Per Share:**Income
                before
                discontinued operations
            
            
            
            
            $
            0.91
            
            $
            0.54
            
            $
            0.37
            
            $
            1.58
            
            $
            0.97
            
            $
            0.61Discontinued
                operations
            
            
            
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            0.05
            
            
            (0.05
            )Net
                earnings
                per diluted share
            
            
            
            
            $
            0.91
            
            $
            0.54
            
            $
            0.37
            
            $
            1.58
            
            $
            1.02
            
            $
            0.56





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





Net
      income in the
      second quarter and the first six months of 2006 included net losses associated
      with the sale and impairment of non-core assets of $9 million (or $0.03 per
      share) and $11 million (or $0.03 per share), respectively.




Net income in the second quarter of 2005 included a net gain resulting from
      the
      JCP&L rate settlement of $16 million (or $0.05 per share) and
      additional income tax expense of $71 million (or $0.22 per share) from the
      enactment of tax legislation in Ohio. In the first six months of 2005, net
      income was also 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 NRC regarding the
      Davis-Besse Nuclear Power Station.


35





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





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





**Power****Supply**
            
            **Other
                and****Regulated**
            
            **Management**
            
            **Reconciling**
            
            **FirstEnergy****2nd
                Quarter 2006 Financial Results**
            
            **Services**
            
            **Services**
            
            **Adjustments**
            
            **Consolidated*****(In
                millions)***Revenues:ExternalElectric
            
            $
            913
            
            $
            1,640
            
            $
            -
            
            $
            2,553Other
            
            
            132
            
            
            38
            
            
            63
            
            
            233Internal
            
            
            -
            
            
            -
            
            
            -
            
            
            -Total
                Revenues
            
            
            1,045
            
            
            1,678
            
            
            63
            
            
            2,786Expenses:Fuel
                and
                purchased power
            
            
            -
            
            
            992
            
            
            -
            
            
            992Other
                operating expenses
            
            
            283
            
            
            406
            
            
            71
            
            
            760Provision
                for
                depreciation
            
            
            88
            
            
            50
            
            
            6
            
            
            144Amortization
                of regulatory assets
            
            
            195
            
            
            4
            
            
            -
            
            
            199Deferral
                of
                new regulatory assets
            
            
            (55
            )
            
            (90
            )
            
            -
            
            
            (145
            )General
                taxes
            
            
            129
            
            
            39
            
            
            5
            
            
            173Total
                Expenses
            
            
            640
            
            
            1.401
            
            
            82
            
            
            2,123Operating
                Income (Loss)
            
            
            405
            
            
            277
            
            
            (19
            )
            
            663Other
                Income
                (Expense):Investment
                income
            
            
            75
            
            
            2
            
            
            (46
            )
            
            31Interest
                expense
            
            
            (96
            )
            
            (56
            )
            
            (26
            )
            
            (178
            )Capitalized
                interest
            
            
            5
            
            
            2
            
            
            -
            
            
            7Subsidiaries'
                preferred stock dividends
            
            
            (5
            )
            
            -
            
            
            3
            
            
            (2
            )Total
                Other
                Income (Expense)
            
            
            (21
            )
            
            (52
            )
            
            (69
            )
            
            (142
            )Income
                taxes
                (benefit)
            
            
            155
            
            
            90
            
            
            (28
            )
            
            217Income
                before
                discontinued operations
            
            
            229
            
            
            135
            
            
            (60
            )
            
            304Discontinued
                operations
            
            
            -
            
            
            -
            
            
            -
            
            
            -Net
                Income
                (Loss)
            
            $
            229
            
            $
            135
            
            $
            (60
            )
            $
            304





**Power****Supply**
            
            **Other
                and****Regulated**
            
            **Management**
            
            **Reconciling**
            
            **FirstEnergy****2nd
                Quarter 2005 Financial Results**
            
            **Services**
            
            **Services**
            
            **Adjustments**
            
            **Consolidated*****(In
                millions)***Revenues:ExternalElectric
            
            $
            1,087
            
            $
            1,391
            
            $
            -
            
            $
            2,478Other
            
            
            139
            
            
            25
            
            
            201
            
            
            365Internal
            
            
            80
            
            
            -
            
            
            (80
            )
            
            -Total
                Revenues
            
            
            1,306
            
            
            1,416
            
            
            121
            
            
            2,843Expenses:Fuel
                and
                purchased power
            
            
            -
            
            
            933
            
            
            -
            
            
            933Other
                operating expenses
            
            
            297
            
            
            469
            
            
            107
            
            
            873Provision
                for
                depreciation
            
            
            138
            
            
            4
            
            
            7
            
            
            149Amortization
                of regulatory assets
            
            
            306
            
            
            -
            
            
            -
            
            
            306Deferral
                of
                new regulatory assets
            
            
            (100
            )
            
            (20
            )
            
            -
            
            
            (120
            )General
                taxes
            
            
            132
            
            
            31
            
            
            5
            
            
            168Total
                Expenses
            
            
            773
            
            
            1,417
            
            
            119
            
            
            2,309Operating
                Income (Loss)
            
            
            533
            
            
            (1
            )
            
            2
            
            
            534Other
                Income
                (Expense):Investment
                income
            
            
            47
            
            
            -
            
            
            -
            
            
            47Interest
                expense
            
            
            (99
            )
            
            (10
            )
            
            (53
            )
            
            (162
            )Capitalized
                interest
            
            
            4
            
            
            1
            
            
            -
            
            
            5Subsidiaries'
                preferred stock dividends
            
            
            (4
            )
            
            -
            
            
            -
            
            
            (4
            )Total
                Other
                Income (Expense)
            
            
            (52
            )
            
            (9
            )
            
            (53
            )
            
            (114
            )Income
                taxes
                (benefit)
            
            
            193
            
            
            (5
            )
            
            53
            
            
            241Income
                before
                discontinued operations
            
            
            288
            
            
            (5
            )
            
            (104
            )
            
            179Discontinued
                operations
            
            
            -
            
            
            -
            
            
            (1
            )
            
            (1
            )Net
                Income
                (Loss)
            
            $
            288
            
            $
            (5
            )
            $
            (105
            )
            $
            178





36





**Power****Change
                Between 2nd Quarter 2006 and**
            
            
            
            **Supply**
            
            **Other
                and****2nd
                Quarter 2005 Financial Results**
            
            **Regulated**
            
            **Management**
            
            **Reconciling**
            
            **FirstEnergy****Increase
                (Decrease)**
            
            **Services**
            
            **Services**
            
            **Adjustments**
            
            **Consolidated*****(In
                millions)***Revenues:ExternalElectric
            
            $
            (174
            )
            $
            249
            
            $
            -
            
            $
            75Other
            
            
            (7
            )
            
            13
            
            
            (138
            )
            
            (132
            )Internal
            
            
            (80
            )
            
            -
            
            
            80
            
            
            -Total
                Revenues
            
            
            (261
            )
            
            262
            
            
            (58
            )
            
            (57
            )Expenses:Fuel
                and
                purchased power
            
            
            -
            
            
            59
            
            
            -
            
            
            59Other
                operating expenses
            
            
            (14
            )
            
            (63
            )
            
            (36
            )
            
            (113
            )Provision
                for
                depreciation
            
            
            (50
            )
            
            46
            
            
            (1
            )
            
            (5
            )Amortization
                of regulatory assets
            
            
            (111
            )
            
            4
            
            
            -
            
            
            (107
            )Deferral
                of
                new regulatory assets
            
            
            45
            
            
            (70
            )
            
            -
            
            
            (25
            )General
                taxes
            
            
            (3
            )
            
            8
            
            
            -
            
            
            5Total
                Expenses
            
            
            (133
            )
            
            (16
            )
            
            (37
            )
            
            (186
            )Operating
                Income
            
            
            (128
            )
            
            278
            
            
            (21
            )
            
            129Other
                Income
                (Expense):Investment
                income
            
            
            28
            
            
            2
            
            
            (46
            )
            
            (16
            )Interest
                expense
            
            
            3
            
            
            (46
            )
            
            27
            
            
            (16
            )Capitalized
                interest
            
            
            1
            
            
            1
            
            
            -
            
            
            2Subsidiaries'
                preferred stock dividends
            
            
            (1
            )
            
            -
            
            
            3
            
            
            2Total
                Other
                Income (Expense)
            
            
            31
            
            
            (43
            )
            
            (16
            )
            
            (28
            )Income
                taxes
            
            
            (38
            )
            
            95
            
            
            (81
            )
            
            (24
            )Income
                before
                discontinued operations
            
            
            (59
            )
            
            140
            
            
            44
            
            
            125Discontinued
                operations
            
            
            -
            
            
            -
            
            
            1
            
            
            1Net
                Income
            
            $
            (59
            )
            $
            140
            
            $
            45
            
            $
            126





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





Net
      income decreased
      $59 million (20.5%) to $229 million in the second quarter of 2006 compared
      to
      $288 million in the second 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 June 30,****Increase****Revenues
                By Type of Service**
            
            **2006**
            
            **2005**
            
            **(Decrease)*****(In
                millions)***Distribution
                services
            
            $
            913
            
            $
            1,087
            
            $
            (174
            )Transmission
                services
            
            
            87
            
            
            105
            
            
            (18
            )Internal
                lease
                revenues
            
            
            -
            
            
            80
            
            
            (80
            )Other
            
            
            45
            
            
            34
            
            
            11Total
                Revenues
            
            $
            1,045
            
            $
            1,306
            
            $
            (261
            )





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





**Electric
                Distribution Deliveries**Residential
            
            
            (4.8
            )%Commercial
            
            
            (1.1
            )%Industrial
            
            
            0.4
            %Total
                Distribution Deliveries
            
            
            (1.8
            )%





37


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 w ith
        lower KWH
        deliveries, resulted in lower distribution delivery revenues.  The decrease
        in deliveries to customers was primarily due to unseasonably milder weather
        during the second quarter of 2006.  The following table summarizes major
        factors contributing to the $174 million decrease in distribution service
        revenues in the second quarter of 2006:





**Sources
                of Change in Distribution Revenues**
            
            **Increase**
              **(Decrease)*****(In
                millions)***Changes
                in
                customer usage
            
            $
            (54
            )Ohio
                shopping
                incentives
            
            
            58Changes
                in
                prices:Rate
                mix and
                other
            
            
            (178
            )Net
                Decrease
                in Distribution Revenues
            
            $
            (174
            )





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.





*Expenses-*





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




·
            Other
                operating expenses were $14 million lower in 2006 due, in part, to
                the
                following factors:




1)
            The
                absence in
                2006 of expenses for ancillary service refunds to third parties of
                $6 million in 2005 due to the RCP, which provides that alternate
                suppliers of ancillary services now bill customers directly for those
                services;





2)
            A
                $27 million decrease in employee and contractor costs resulting from
                lower storm-related expenses, reduced employee benefits (principally
                postretirement benefits) and the decreased use of outside contractors
                for
                tree trimming, reliability work, legal services and jobbing and
                contracting; and





3)
            An
                $18 million increase due in part to insurance premium costs,
                financing fees and other administrative
                costs.





·
            Lower
                depreciation expense of $50 million that resulted from the impact
                of the
                generation asset transfers;





·
            Reduced
                amortization of regulatory assets of $111 million principally due
                to the
                completion of Ohio generation transition cost recovery and Penn's
                transition plan in 2005; and





·
            General
                taxes
                decreased by $3million
                primarily due to lower property taxes as a result of the generation
                asset
                transfers.




The
      reduction in the deferral of new regulatory assets resulted from the 2005
      JCP&L rate decision and the end of shopping incentive deferrals under the
      Ohio Companies’ transition plan, partially offset by the distribution cost
      deferrals under the Ohio Companies’ RCP.





*Other
      Income
      -*





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 second quarter of 2006 was 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.





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


******


******Net
      income for this
      segment was $135 million in the second quarter of 2006 compared to a net loss
      of
      $5 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.


38





*Revenues
      -*




Electric generation sales revenues increased $224 million in the second quarter
      of 2006 compared to the same period in 2005. This increase primarily resulted
      from a 7.7% increase in retail KWH sales, mostly due to the return of customers
      as a result of third-party suppliers leaving the Ohio marketplace, and higher
      unit prices resulting from the 2006 rate stabilization and fuel recovery
      charges. Additional retail sales reduced energy available for sale to the
      wholesale market. Increased transmission revenues reflected new revenues of
      approximately $27 million under the MISO transmission rider that began in the
      first quarter of 2006.





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





**Three
                Months Ended June 30,****Increase****Revenues
                By Type of Service**
            
            **2006**
            
            **2005**
            
            **(Decrease)*****(In
                millions)***Electric
                Generation Sales:Retail
            
            $
            1,285
            
            $
            989
            
            $
            296Wholesale
            
            
            253
            
            
            325
            
            
            (72
            )Total
                Electric
                Generation Sales
            
            
            1,538
            
            
            1,314
            
            
            224Transmission
            
            
            134
            
            
            93
            
            
            41Other
            
            
            6
            
            
            9
            
            
            (3
            )Total
                Revenues
            
            $
            1,678
            
            $
            1,416
            
            $
            262





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





**Increase****Source
                of Change in Electric Generation Sales**
            
            **(Decrease)*****(In
                millions)***Retail:Effect
                of 7.7%
                increase in customer usage
            
            $
            76Increased
                prices
            
            
            220296Wholesale:Effect
                of 8.4%
                decrease in KWH sales
            
            
            (27
            )Lower
                prices
            
            
            (45
            )(72
            )Net
                Increase
                in Electric Generation Sales
            
            $
            224





*Expenses
      -*





Total
      operating
      expenses decreased by $16 million.
      The
      decrease was due to the following factors:





·
            Lower
                non-fuel
                operating expenses of $63 million reflect the absence in 2006 of
                generating lease rents of $80 million in 2005 due to the generation
                asset transfers, partially offset by higher transmission expenses
                of
                $11 million related to the transmission revenues discussed above;
                and





·
            The
                $70 million increase in the deferral of new regulatory assets
                represents PJM/MISO costs incurred that are expected to be recovered
                from
                customers through future rates. The recognition of these amounts
                under the
                Power Supply Management Services segment reflects a change in the
                current
                year operations reporting as discussed in Note 13 - Segment Information.
                Retail transmission revenues and PJM/MISO transmission revenues and
                expenses associated with serving electricity load are now included
                in the
                power supply management services segment results. The deferrals in
                2006
                also include the Ohio RCP fuel deferral of
                $29 million.





39





The
      above decreases
      were partially offset by the following:





·
            Higher
                fuel
                and purchased power costs of $59million,
                including increased fuel costs of $23million
                - coal
                costs increased $40million
                as a
                result of increased generation output, higher coal commodity prices
                and
                increased transportation costs for western coal. The increased coal
                costs
                were partially offset by lower natural gas and emission allowance
                costs of
                $20 million. Purchased power costs increased $36million
                due to
                higher prices and increased volumes. Factors producing the higher
                costs
                are summarized in the following table:





**Increase****Source
                of Change in Fuel and Purchased Power**
            
            **(Decrease)*****(In
                millions)***Fuel:Change
                due to
                increased unit costs
            
            $
            5Change
                due to
                volume consumed
            
            
            1823Purchased
                Power:Change
                due to
                increased unit costs
            
            
            53Change
                due to
                volume purchased
            
            
            2Increase
                in
                NUG costs deferred
            
            
            (19
            )36Net
                Increase
                in Fuel and Purchased Power Costs
            
            $
            59








·
            Increased
                depreciation expenses of $46 million resulted principally from the
                generation asset transfers; and





·
            Higher
                general
                taxes of $8million
                due to
                additional property taxes resulting from the generation asset
                transfers.





*Other
      Income and
      Expense -*




·
            Investment
                income in the second quarter of 2006 increased by $2 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 that financed the generation
                  asset transfers.




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


FirstEnergy’s financial results from other operating segments and reconciling
      items, including interest expense on holding company debt and corporate support
      services revenues and expenses, resulted in a $45 million increase to
      FirstEnergy’s net income in the second quarter of 2006 compared to the same
      quarter of 2005. The increase was primarily due to the absence of an adjustment
      from the effect of Ohio tax legislation in June 2005, which resulted in
      additional 2005 tax expenses of $71 million, and a $3 million gain
      related to interest rate swap financing arrangements. These increases were
      partially offset by a $5 million reduction in investment income, non-core
      asset sales gains/impairments of $9 million and a $7 million reduction
      in gas commodity trading results.


40





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





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





**Power****Supply**
            
            **Other
                and****Regulated**
            
            **Management**
            
            **Reconciling**
            
            **FirstEnergy****First
                Six Months of 2006 Financial Results**
            
            **Services**
            
            **Services**
            
            **Adjustments**
            
            **Consolidated*****(In
                millions)***Revenues:ExternalElectric
            
            $
            1,848
            
            $
            3,216
            
            $
            -
            
            $
            5,064Other
            
            
            280
            
            
            81
            
            
            206
            
            
            567Internal
            
            
            -
            
            
            -
            
            
            -
            
            
            -Total
                Revenues
            
            
            2,128
            
            
            3,297
            
            
            206
            
            
            5,631Expenses:Fuel
                and
                purchased power
            
            
            -
            
            
            1,990
            
            
            -
            
            
            1,990Other
                operating expenses
            
            
            582
            
            
            856
            
            
            215
            
            
            1,653Provision
                for
                depreciation
            
            
            184
            
            
            96
            
            
            12
            
            
            292Amortization
                of regulatory assets
            
            
            412
            
            
            9
            
            
            -
            
            
            421Deferral
                of
                new regulatory assets
            
            
            (110
            )
            
            (116
            )
            
            -
            
            
            (226
            )General
                taxes
            
            
            269
            
            
            84
            
            
            13
            
            
            366Total
                Expenses
            
            
            1,337
            
            
            2,919
            
            
            240
            
            
            4,496Operating
                Income (Loss)
            
            
            791
            
            
            378
            
            
            (34
            )
            
            1,135Other
                Income
                (Expense):Investment
                income
            
            
            137
            
            
            17
            
            
            (80
            )
            
            74Interest
                expense
            
            
            (190
            )
            
            (109
            )
            
            (44
            )
            
            (343
            )Capitalized
                interest
            
            
            8
            
            
            6
            
            
            -
            
            
            14Subsidiaries'
                preferred stock dividends
            
            
            (7
            )
            
            -
            
            
            3
            
            
            (4
            )Total
                Other
                Income (Expense)
            
            
            (52
            )
            
            (86
            )
            
            (121
            )
            
            (259
            )Income
                taxes
                (benefit)
            
            
            299
            
            
            117
            
            
            (65
            )
            
            351Income
                before
                discontinued operations
            
            
            440
            
            
            175
            
            
            (90
            )
            
            525Discontinued
                operations
            
            
            -
            
            
            -
            
            
            -
            
            
            -Net
                Income
                (Loss)
            
            $
            440
            
            $
            175
            
            $
            (90
            )
            $
            525


41





**Power****Supply**
            
            **Other
                and****Regulated**
            
            **Management**
            
            **Reconciling**
            
            **FirstEnergy****First
                Six Months of 2005 Financial Results**
            
            **Services**
            
            **Services**
            
            **Adjustments**
            
            **Consolidated*****(In
                millions)***Revenues:ExternalElectric
            
            $
            2,169
            
            $
            2,746
            
            $
            -
            
            $
            4,915Other
            
            
            273
            
            
            47
            
            
            358
            
            
            678Internal
            
            
            158
            
            
            -
            
            
            (158
            )
            
            -Total
                Revenues
            
            
            2,600
            
            
            2,793
            
            
            200
            
            
            5,593Expenses:Fuel
                and
                purchased power
            
            
            -
            
            
            1,828
            
            
            -
            
            
            1,828Other
                operating expenses
            
            
            625
            
            
            968
            
            
            164
            
            
            1,757Provision
                for
                depreciation
            
            
            261
            
            
            17
            
            
            14
            
            
            292Amortization
                of regulatory assets
            
            
            617
            
            
            -
            
            
            -
            
            
            617Deferral
                of
                new regulatory assets
            
            
            (160
            )
            
            (20
            )
            
            -
            
            
            (180
            )General
                taxes
            
            
            274
            
            
            67
            
            
            12
            
            
            353Total
                Expenses
            
            
            1,617
            
            
            2,860
            
            
            190
            
            
            4,667Operating
                Income (Loss)
            
            
            983
            
            
            (67
            )
            
            10
            
            
            926Other
                Income
                (Expense):Investment
                income
            
            
            88
            
            
            -
            
            
            -
            
            
            88Interest
                expense
            
            
            (194
            )
            
            (16
            )
            
            (116
            )
            
            (326
            )Capitalized
                interest
            
            
            7
            
            
            (3
            )
            
            -
            
            
            4Subsidiaries'
                preferred stock dividends
            
            
            (10
            )
            
            -
            
            
            -
            
            
            (10
            )Total
                Other
                Income (Expense)
            
            
            (109
            )
            
            (19
            )
            
            (116
            )
            
            (244
            )Income
                taxes
                (benefit)
            
            
            350
            
            
            (35
            )
            
            47
            
            
            362Income
                before
                discontinued operations
            
            
            524
            
            
            (51
            )
            
            (153
            )
            
            320Discontinued
                operations
            
            
            -
            
            
            -
            
            
            18
            
            
            18Net
                Income
                (Loss)
            
            $
            524
            
            $
            (51
            )
            $
            (135
            )
            $
            338





**Power****Change
                Between First Six Months of 2006**
            
            
            
            **Supply**
            
            **Other
                and****and
                First Six Months of 2005**
            
            **Regulated**
            
            **Management**
            
            **Reconciling**
            
            **FirstEnergy****Financial
                Results**-**Increase (Decrease)**
            
            **Services**
            
            **Services**
            
            **Adjustments**
            
            **Consolidated*****(In
                millions)***Revenues:ExternalElectric
            
            $
            (321
            )
            $
            470
            
            $
            -
            
            $
            149Other
            
            
            7
            
            
            34
            
            
            (152
            )
            
            (111
            )Internal
            
            
            (158
            )
            
            -
            
            
            158
            
            
            -Total
                Revenues
            
            
            (472
            )
            
            504
            
            
            6
            
            
            38Expenses:Fuel
                and
                purchased power
            
            
            -
            
            
            162
            
            
            -
            
            
            162Other
                operating expenses
            
            
            (43
            )
            
            (112
            )
            
            51
            
            
            (104
            )Provision
                for
                depreciation
            
            
            (77
            )
            
            79
            
            
            (2
            )
            
            -Amortization
                of regulatory assets
            
            
            (205
            )
            
            9
            
            
            -
            
            
            (196
            )Deferral
                of
                new regulatory assets
            
            
            50
            
            
            (96
            )
            
            -
            
            
            (46
            )General
                taxes
            
            
            (5
            )
            
            17
            
            
            1
            
            
            13Total
                Expenses
            
            
            (280
            )
            
            59
            
            
            50
            
            
            (171
            )Operating
                Income
            
            
            (192
            )
            
            445
            
            
            (44
            )
            
            209Other
                Income
                (Expense):Investment
                income
            
            
            49
            
            
            17
            
            
            (80
            )
            
            (14
            )Interest
                expense
            
            
            4
            
            
            (93
            )
            
            72
            
            
            (17
            )Capitalized
                interest
            
            
            1
            
            
            9
            
            
            -
            
            
            10Subsidiaries'
                preferred stock dividends
            
            
            3
            
            
            -
            
            
            3
            
            
            6Total
                Other
                Income (Expense)
            
            
            57
            
            
            (67
            )
            
            (5
            )
            
            (15
            )Income
                taxes
            
            
            (51
            )
            
            152
            
            
            (112
            )
            
            (11
            )Income
                before
                discontinued operations
            
            
            (84
            )
            
            226
            
            
            63
            
            
            205Discontinued
                operations
            
            
            -
            
            
            -
            
            
            (18
            )
            
            (18
            )Net
                Income
            
            $
            (84
            )
            $
            226
            
            $
            45
            
            $
            187


42


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





Net
      income decreased
      $84 million (16.0%) to $440 million in the first six months of 2006 compared
      to
      $524 million in the first six months 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:





**Six
                Months Ended June 30,****Increase****Revenues
                By Type of Service**
            
            **2006**
            
            **2005**
            
            **(Decrease)*****(In
                millions)***Distribution
                services
            
            $
            1,848
            
            $
            2,169
            
            $
            (321
            )Transmission
                services
            
            
            181
            
            
            197
            
            
            (16
            )Internal
                lease
                revenues
            
            
            -
            
            
            158
            
            
            (158
            )Other
            
            
            99
            
            
            76
            
            
            23Total
                Revenues
            
            $
            2,128
            
            $
            2,600
            
            $
            (472
            )





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





**Electric
                Distribution Deliveries**Residential
            
            
            (3.6
            )%Commercial
            
            
            (1.6
            )%Industrial
            
            
            (1.2
            )%Total
                Distribution Deliveries
            
            
            (2.2
            )%





The
      completion of
      the Ohio Companies' generation transition cost recovery under their respective
      transition plans and Penn's transition plan in 2005 was the primary reason
      for
      lower distribution unit prices, which, in conjunction with lower KWH deliveries,
      resulted in lower distribution delivery revenues. The decreases in deliveries
      to
      customers were primarily due to unseasonably milder weather during the first
      six
      months of 2006 as compared to the same period in 2005. The following table
      summarizes major factors contributing to the $321 million decrease in
      distribution service revenues in the first six months of 2006:





**Sources
                of Change in Distribution Revenues**
            
            **Increase**
              **(Decrease)*****(In
                millions)***Changes
                in
                customer usage
            
            $
            (102
            )Ohio
                shopping
                incentives
            
            
            100Changes
                in
                prices:Rate
                mix and
                other
            
            
            (319
            )Net
                Decrease
                in Distribution Revenues
            
            $
            (321
            )





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.





*Expenses-*





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





·
            Other
                operating expenses were $43 million lower in 2006 due, in part, to
                the
                following factors:


1)
            The
                absence in
                2006 of expenses for ancillary service refunds to third parties of
                $13 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
                $6 million incurred in 2005;
                and


43





3)
            A
                $33 million
                decrease in employee and contractor costs resulting from lower
                storm-related expenses, reduced employee benefits and the decreased
                use of
                outside contractors for tree trimming, reliability work, legal services
                and jobbing and contracting.





·
            Lower
                depreciation expense of $77 million resulted from the impact of the
                generation asset transfers;





·
            Reduced
                amortization of regulatory assets of $205 million resulted principally
                from the completion of Ohio generation transition cost recovery and
                Penn's
                transition plan in 2005; and





·
            General
                taxes
                decreased by $5 million primarily due to lower property taxes as
                a result
                of the generation asset transfers.





The
      reduction in the
      deferral of new regulatory assets resulted from the 2005 JCP&L rate decision
      and the end of shopping incentive deferrals under the Ohio Companies’ transition
      plan, partially offset by the distribution cost deferrals under the Ohio
      Companies’ RCP.





*Other
      Income and
      Expense -*





·
            Higher
                investment income reflects the impact of the generation asset transfers.
                Interest income on the affiliated company notes receivable from the
                power
                supply management services segment in the first six months 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 $3 million in 2006 due to
                redemption activity in 2005.





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





Net
      income for this
      segment was $175 million in the first six months of 2006 compared to a net
      loss
      of $51 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 $423 million in the first six months of 2006
      compared to the same period in 2005. This increase primarily resulted from
      a
      7.2% increase in retail KWH sales, mostly due to the return of customers as
      a
      result of third-party suppliers leaving the Ohio marketplace, and higher unit
      prices resulting from the RSP and RCP that were effective in 2006. The higher
      retail sales reduced energy available for sale to the wholesale market.
      Increased transmission revenues reflected new revenues of approximately $54
      million under the MISO transmission rider that began in the first quarter of
      2006. These increases were partially offset by a reduction in wholesale sales
      revenue as a result of both lower KWH sales and lower unit prices.





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





**Six
                Months Ended June 30,****Increase****Revenues
                By Type of Service**
            
            **2006**
            
            **2005**
            
            **(Decrease)*****(In
                millions)***Electric
                Generation Sales:Retail
            
            $
            2,524
            
            $
            1,969
            
            $
            555Wholesale
            
            
            488
            
            
            620
            
            
            (132
            )Total
                Electric
                Generation Sales
            
            
            3,012
            
            
            2,589
            
            
            423Transmission
            
            
            262
            
            
            182
            
            
            80Other
            
            
            23
            
            
            22
            
            
            1Total
                Revenues
            
            $
            3,297
            
            $
            2,793
            
            $
            504





44





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





**Increase****Source
                of Change in Electric Generation Sales**
            
            **(Decrease)*****(In
                millions)***Retail:Effect
                of 7.2%
                increase in customer usage
            
            $
            141Change
                in
                prices
            
            
            414555Wholesale:Effect
                of
                11.9% decrease in KWH sales
            
            
            (74
            )Change
                in
                prices
            
            
            (58
            )(132
            )Net
                Increase
                in Electric Generation Sales
            
            $
            423





*Expenses
      -*





Total
      operating
      expenses increased by $59 million.
      The
      increase was due to the following factors:





·
            Higher
                fuel
                and purchased power costs of $162 million, including increased fuel
                costs of $73 million - coal costs increased $81 million as a result
                of increased generation output, higher coal commodity prices and
                increased
                transportation costs for western coal. The increased coal costs were
                partially offset by lower natural gas and emission allowance costs
                of
                $16 million. Purchased power costs increased $89 million due to
                higher prices partially offset by lower volumes. Factors contributing
                to
                the higher costs are summarized in the following table:





**Increase****Source
                of Change in Fuel and Purchased Power**
            
            **(Decrease)*****(In
                millions)***Fuel:Change
                due to
                increased unit costs
            
            $
            37Change
                due to
                volume consumed
            
            
            3673Purchased
                Power:Change
                due to
                increased unit costs
            
            
            130Change
                due to
                volume purchased
            
            
            (31
            )Increase
                in
                NUG costs deferred
            
            
            (10
            )89Net
                Increase
                in Fuel and Purchased Power Costs
            
            $
            162





·
            Higher
                transmission expenses of $42 million related to the transmission
                revenues
                discussed above;





·
            Increased
                depreciation expenses of $79 million, resulting principally from
                the
                generation asset transfers; and





·
            Higher
                general
                taxes of $17 million due to additional property taxes resulting from
                the
                generation asset transfers.




Partially offsetting these higher costs were lower non-fuel operating expenses
      of $112 million, which reflect the absence in 2006 of generating asset
      lease rents of $158 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.




The
      $96 million increase in the deferral of new regulatory assets represents
      PJM/MISO costs incurred that are expected to be recovered from customers through
      future rates. The deferrals also include the Ohio RCP fuel deferral of
      $51 million.


45





*Other
      Income and
      Expense -*





·
            Investment
                income in the first six months of 2006 was $17 million higher primarily
                due to nuclear decommissioning trust investments acquired through
                the
                generation asset transfers; and·
            Interest
                expense increased by $93 million, primarily due to interest on the
                associated company notes payable from the generation asset transfers.
                This
                increase was partially offset by an additional $9 million of
                capitalized interest.





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





FirstEnergy’s
      financial results from other operating segments and reconciling items, including
      interest expense on holding company debt and corporate support services revenues
      and expenses, resulted in a $45 million increase to FirstEnergy’s net
      income in the first six months of 2006 compared to the same period of 2005.
      The
      increase was primarily due to the absence of the write-off of income tax
      benefits due to the 2005 change in Ohio tax legislation, the financing swap
      gain
      described in the Other - Second Quarter 2006 Compared to Second Quarter 2005
      results analysis above and a $3 million increase in other investment income
      in
      the first half of 2006. These increases were partially offset by the FSG
      impairment charge and gas commodity trading results reduction and the absence
      of
      after - tax gains of $17 million from discontinued operations in 2005 (see
      Note 4). The following table summarizes the sources of income from discontinued
      operations for the six months ended June 30, 2005:





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





**CAPITAL
      RESOURCES AND LIQUIDITY**




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. FirstEnergy
      paid cash dividends to common shareholders of $148 million in each quarter
      of
      2006 totaling $296 million for the first six months of 2006. FirstEnergy
      received $148 million of cash dividends from its subsidiaries in the first
      quarter of 2006 and borrowed against the $2.0 billion revolving credit facility
      for the second quarter dividend payment. In July, FirstEnergy received
      $500 million from OE as a result of OE’s repurchase of common stock. There
      are no material restrictions on the payment of cash dividends by FirstEnergy's
      subsidiaries.




As of June 30, 2006, FirstEnergy had $583 million of cash and cash
      equivalents compared with $64 million as of December 31, 2005.
      Temporary cash investments of $544 million were used principally to redeem
      $400 million of the outstanding $1 billion of FirstEnergy’s 5.5% notes
      in July 2006, in advance of their November 15, 2006 maturity date. The remainder
      was used in July 2006 to redeem $61 million of OE’s preferred stock and
      reduce short-term borrowings. The major sources for changes in cash and cash
      equivalent balances are summarized below.


46


***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
      $551 million and $921 million in the first six months of 2006 and 2005,
      respectively, summarized as follows:





**Six
                Months Ended****June
                30,****Operating
                Cash Flows**
            
            **2006**
            
            **2005*****(In
                millions)***Cash
                earnings
                *
            
            $
            771
            
            $
            827Working
                capital and other
            
            
            (220
            )
            
            94Net
                cash
                provided from operating activities
            
            $
            551
            
            $
            921*
                Cash
                earnings are a Non-GAAP measure (see reconciliation
                below).





Cash
      earnings (in
      the table above) are not a measure of performance calculated in accordance
      with
      GAAP. FirstEnergy believes that cash earnings 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.





**Six
                Months Ended****June
                30,****Reconciliation
                of Cash Earnings**
            
            **2006**
            
            **2005*****(In
                millions)***Net
                income
                (GAAP)
            
            $
            525
            
            $
            338Non-cash
                charges (credits):Provision
                for
                depreciation
            
            
            292
            
            
            292Amortization
                of regulatory assets
            
            
            421
            
            
            617Deferral
                of
                new regulatory assets
            
            
            (226
            )
            
            (180
            )Nuclear
                fuel
                and lease amortization
            
            
            30
            
            
            38Deferred
                purchased power and other costs
            
            
            (239
            )
            
            (210
            )Deferred
                income taxes and investment tax credits
            
            
            32
            
            
            62Deferred
                rents
                and lease market valuation liability
            
            
            (105
            )
            
            (101
            )Accrued
                compensation and retirement benefits
            
            
            33
            
            
            11Income
                from
                discontinued operations
            
            
            -
            
            
            (18
            )Other
                non-cash
                expenses
            
            
            8
            
            
            (22
            )Cash
                earnings
                (Non-GAAP)
            
            $
            771
            
            $
            827





Net
      cash provided
      from operating activities decreased by $370 million in the first six months
      of 2006 compared to the first six months of 2005 primarily due to a
      $314 million decrease from working capital and a $56 million decrease
      in cash earnings described under "Results of Operations." The decrease from
      working capital changes primarily resulted from $242 million of funds
      received in 2005 for prepaid electric service (under a three-year Energy for
      Education Program with the Ohio Schools Council), increased outflows of
      $144 million for payables primarily caused by higher fuel and purchased
      power costs, and $77 million of cash collateral returned to suppliers.
      These decreases were partially offset by an increase in cash provided from
      the
      settlement of receivables of $218 million, reflecting increased electric sales
      revenues.


47





***Cash
      Flows From Financing Activities***





In
      the first six
      months of 2006, cash provided from financing activities was $616 million
      compared to cash used for financing activities of $468 million in the first
      six
      months of 2005. The following table summarizes security issuances and
      redemptions.





**Six
                Months Ended****June
                30,****Securities
                Issued or Redeemed**
            
            **2006**
            
            **2005*****(In
                millions)****New
                issues*Pollution
                control notes
            
            $
            253
            
            $
            245Secured
                notes
            
            
            200
            
            
            -Unsecured
                notes
            
            
            600
            
            
            -$
            1,053
            
            $
            245*Redemptions*First
                mortgage
                bonds
            
            $
            1
            
            $
            178Pollution
                control notes
            
            
            307
            
            
            247Secured
                notes
            
            
            179
            
            
            49Long-term
                revolving credit
            
            
            -
            
            
            215Preferred
                stock
            
            
            30
            
            
            140$
            517
            
            $
            829Short-term
                borrowings, net
            
            $
            371
            
            $
            386





FirstEnergy
      had
      approximately $1.1 billion of short-term indebtedness as of June 30,
      2006 compared to approximately $731 million as of December 31, 2005.
      This increase was due primarily to higher capital expenditures and common
      dividend payments compared to Net Cash from Operating Activities during the
      first half of the year. Available bank borrowing capability as of June 30,
      2006 included the following:





**Borrowing
                Capability*****(In
                millions)***Short-term
                credit facilities(1)
            
            $
            2,120Accounts
                receivable financing facilities
            
            
            550Utilized
            
            
            (1,096
            )LOCs
            
            
            (123
            )Net
            
            $
            1,451(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 June 30, 2006, the Ohio Companies and Penn had the aggregate capability
      to
      issue approximately $1.5 billion of additional FMB on the basis of property
      additions and retired bonds under the terms of their respective mortgage
      indentures. The issuance of FMB by OE and CEI are also subject to provisions
      of
      their senior note indentures generally limiting the incurrence of additional
      secured debt, subject to certain exceptions that would permit, among other
      things, the issuance of secured debt (including FMB) (i) supporting pollution
      control notes or similar obligations, or (ii) as an extension, renewal or
      replacement of previously outstanding secured debt. In addition, these
      provisions would permit OE and CEI to incur additional secured debt not
      otherwise permitted by a specified exception of up to $735 million and
      $576 million, respectively, as of June 30, 2006. Under the provisions
      of its senior note indenture, JCP&L may issue additional FMB only as
      collateral for senior notes. As of June 30, 2006, JCP&L had the capability
      to issue $610 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 $5 billion of preferred stock
      (assuming no additional debt was issued) as of June 30, 2006. CEI, Met-Ed and
      Penelec do not have similar restrictions and could issue up to the number of
      preferred shares authorized under their respective charters. As a result of
      OE
      redeeming all of its outstanding preferred stock on July 7, 2006, the applicable
      earnings coverage test is inoperative for OE. Accordingly, as of July 7, 2006,
      Penn, TE and JCP&L could issue a total of $2.6 billion of preferred
      stock (assuming no additional debt was issued). In the event that OE issues
      preferred stock in the future, the applicable earnings coverage test will govern
      the amount of additional preferred stock that OE may issue.


48




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




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 June
      16,
      2010 commitment expiration date.




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





**Revolving**
            
            **Regulatory
                and****Credit
                Facility**
            
            **Other
                Short-Term****Borrower**
            
            **Sub-Limit**
            
            **Debt
                Limitations****1*****(In
                millions)*****FirstEnergy**
            
            $
            2,000
            
            $
            1,500**OE**
            
            
            500
            
            
            500**Penn**
            
            
            50
            
            
            44**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 June 30,
                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- LC b S&P and Baa3 by Moody's or (ii)
                FirstEnergy has guaranteed the obligations of such borrower under
                the
                facility.




The
      revolving credit
      facility, combined with an aggregate $550 million ($249 million unused as
      of June 30, 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 $1.5 billion as of June 30,
      2006.




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





**Borrower****FirstEnergy**
            
            55
            %**OE**
            
            40
            %**Penn**
            
            34
            %**CEI**
            
            49
            %**TE**
            
            28
            %**JCP&L**
            
            29
            %**Met-Ed**
            
            38
            %**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.


49





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 six months of 2006 was approximately 4.86%
      for
      both the regulated companies’ money pool and the unregulated companies' money
      pool.





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





**Issuer**
            
            **Securities**
            
            **S&P**
            
            **Moody’s**
            
            **Fitch****FirstEnergy**
            
            Senior
                unsecured
            
            BBB-
            
            Baa3
            
            BBB-**OE**
            
            Senior
                unsecured
            
            BBB-
            
            Baa2
            
            BBB**CEI**
            
            Senior
                secured
            
            BBB
            
            Baa2
            
            BBB-Senior
                unsecured
            
            BBB-
            
            Baa3
            
            BB+**TE**
            
            Senior
                secured
            
            BBB
            
            Baa2
            
            BBB-Preferred
                stock
            
            BB+
            
            Ba2
            
            BB**Penn**
            
            Senior
                secured
            
            BBB+
            
            Baa1
            
            BBB+Senior
                unsecured(1)
            
            BBB-
            
            Baa2
            
            BBBPreferred
                stock
            
            BB+
            
            Ba1
            
            BBB-**JCP&L**
            
            Senior
                secured
            
            BBB+
            
            Baa1
            
            BBB+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, $106.5 million of pollution control revenue refunding
      bonds were issued on behalf of NGC ($60 million at 3.07% and $46.5 million
      at 3.25%). The proceeds from the bonds were used to redeem the following
      Companies' pollution control notes (OE - $60 million at 7.05%, CEI - $27.7
      million at 3.32%, TE - $18.8 million at 3.32%). Also, on April 3, 2006,
      $146.7 million of pollution control revenue refunding bonds were issued on
      behalf of FGCO ($90.1 million at 3.03% and $56.6 million at 3.10%) which were
      used to redeem 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.




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




On June 8, 2006, the NJBPU approved JCP&L's request to issue securitization
      bonds associated with BGS stranded cost deferrals. On August 4, 2006, JCP&L
      Transition Funding II, a wholly owned subsidiary of JCP&L, secured pricing
      on the issuance of $182 million of transition bonds with a weighted average
      interest rate of 5.5%.


50




On June 20, 2006, FirstEnergy's Board of Directors authorized a share repurchase
      program for up to 12 million shares of common stock. At management’s
      discretion shares may be acquired on the open market or through privately
      negotiated transactions, subject to market conditions and other factors. The
      Board’s authorization of the repurchase program does not require FirstEnergy to
      purchase any shares and the program may be terminated at any time. The
      12 million shares represent 3.6% of the common stock currently
      outstanding.




On June 26, 2006, OE issued $600 million of unsecured senior notes,
      comprised of $250 million of 6.4% notes due 2016 and $350 million of 6.875%
      notes due 2036. The majority of the proceeds from this offering were used in
      July 2006 to repurchase $500 million of OE common stock from FirstEnergy,
      enabling FirstEnergy to accelerate repayment of $400 million of senior notes
      that were due to mature in November 2006. The remainder of the proceeds were
      used to redeem approximately $61 million of OE’s preferred stock on July 7, 2006
      and to reduce short-term borrowings. This offering represented an important
      part
      of FirstEnergy’s 2006 financing strategy to obtain additional financing
      flexibility at the holding company level and to capitalize the regulated
      utilities in a way that positions them appropriately in a regulatory context.





***Cash
      Flows From Investing Activities***





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





**Summary
                of Cash Flows**
            
            **Property****Used
                for Investing Activities**
            
            **Additions**
            
            **Investments**
            
            **Other**
            
            **Total****Sources
                (Uses)**
            
            ***(In
                millions)*****Six
                Months Ended June 30, 2006**Regulated
                services
            
            $
            (356
            )
            $
            66
            
            $
            (9
            )
            $
            (299
            )Power
                supply
                management services
            
            
            (347
            )
            
            (24
            )
            
            1
            
            
            (370
            )Other
            
            
            (2
            )
            
            1
            
            
            (5
            )
            
            (6
            )Reconciling
                items
            
            
            (20
            )
            
            37
            
            
            10
            
            
            27Total
            
            $
            (725
            )
            $
            80
            
            $
            (3
            )
            $
            (648
            )**Six
                Months Ended June 30, 2005**Regulated
                services
            
            $
            (299
            )
            $
            9
            
            $
            (7
            )
            $
            (297
            )Power
                supply
                management services
            
            
            (147
            )
            
            14
            
            
            (5
            )
            
            (138
            )Other
            
            
            (5
            )
            
            4
            
            
            (19
            )
            
            (20
            )Reconciling
                items
            
            
            (11
            )
            
            10
            
            
            -
            
            
            (1
            )Total
            
            $
            (462
            )
            $
            37
            
            $
            (31
            )
            $
            (456
            )




Net cash used for investing activities in the first six months of 2006 increased
      by $192 million compared to the first six months of 2005. The increase was
      principally due to a $263 million increase in property additions which
      reflects the replacement of the steam generators and reactor head at Beaver
      Valley Unit 1, air quality control system expenditures and the distribution
      system Accelerated Reliability Improvement Program. The increase in property
      additions was partially offset by a $44 million decrease in net nuclear
      decommissioning trust activities due to the completion of the Ohio Companies'
      and Penn's transition cost recovery for decommissioning at the end of
      2005.




During
      the last half of 2006, capital requirements for property additions and capital
      leases are expected to be approximately $582 million. FirstEnergy and the
      Companies have additional requirements of approximately $1.2 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
      approximately $6.8 billion (excluding nuclear fuel), of which
      $1.2 billion applies to 2006. Investments for additional nuclear fuel
      during the 2006-2010 periods are estimated to be approximately
      $745 million, of which approximately $164 million applies to 2006. During
      the same period, FirstEnergy's nuclear fuel investments are expected to be
      reduced by approximately $564 million and $91 million, respectively,
      as the nuclear fuel is consumed.


51





**GUARANTEES
      AND OTHER ASSURANCES**




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




As of June 30, 2006, FirstEnergy's maximum exposure to potential future
      payments under outstanding guarantees and other assurances totaled approximately
      $3.5 billion, as summarized below:





**Maximum****Guarantees
                and Other Assurances**
            
            **Exposure*****(In
                millions)***FirstEnergy
                Guarantees of Subsidiaries:Energy
                and
                Energy-Related Contracts(1)
            
            $
            814Other(2)
            
            
            1,0811,895Surety
                Bonds
            
            
            146LOC(3)(4)
            
            
            1,471Total
                Guarantees and Other Assurances
            
            $
            3,512





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


(2)
            Issued
                for
                various terms.


(3)
            Includes
                $122
                million issued for various terms under LOC capacity available under
                FirstEnergy’s revolving credit agreement and $730 million outstanding in
                support of pollution control revenue bonds issued with various
                maturities.


(4)
            Includes
                approximately $194 million pledged in connection with the sale and
                leaseback of Beaver Valley Unit 2 by CEI and TE, $291 million pledged
                in
                connection with the sale and leaseback of Beaver Valley Unit 2 by
                OE and
                $134 million pledged in connection with the sale and leaseback of
                Perry 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 June 30,
      2006, FirstEnergy's maximum exposure under these collateral provisions was
      $501
      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 June 30,
      2006) which is renewable and declines yearly based upon the senior outstanding
      debt of TEBSA.


52


**OFF-BALANCE
      SHEET ARRANGEMENTS**




FirstEnergy has obligations that are not included on its Consolidated Balance
      Sheets related to the sale and leaseback arrangements involving Perry, Beaver
      Valley Unit 2 and the Bruce Mansfield Plant, which are satisfied through
      operating lease payments. The present value of these sale and leaseback
      operating lease commitments, net of trust investments, total $1.2 billion
      as of June 30, 2006.








FirstEnergy
      has equity ownership interests in certain businesses that are accounted for
      using the equity method. There are no undisclosed material contingencies related
      to these investments. Certain guarantees that FirstEnergy does not expect to
      have a material current or future effect on its financial condition, liquidity
      or results of operations are disclosed under Guarantees and Other Assurances
      above.





**MARKET
      RISK
      INFORMATION**




FirstEnergy
      uses various market risk sensitive instruments, including derivative contracts,
      primarily to manage the risk of price and interest rate fluctuations.
      FirstEnergy's Risk Policy Committee, comprised of members of senior management,
      provides general oversight to risk management activities throughout FirstEnergy
      and its subsidiaries.





***Commodity
      Price Risk***




FirstEnergy is exposed to financial and market risks resulting from the
      fluctuation of interest rates and commodity prices primarily due to fluctuations
      in electricity, energy transmission, natural gas, coal, nuclear fuel and
      emission allowance prices. To manage the volatility relating to these exposures,
      FirstEnergy uses a variety of non-derivative and derivative instruments,
      including forward contracts, options, futures contracts and swaps. The
      derivatives are used principally for hedging purposes. Derivatives that fall
      within the scope of SFAS 133 must be recorded at their fair value and
      marked to market. The majority of FirstEnergy's derivative hedging contracts
      qualify for the normal purchase and normal sale exception under SFAS 133
      and are therefore excluded from the table below. Contracts that are not exempt
      from such treatment include certain 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. On April 1, 2006, FirstEnergy elected to apply the normal purchase and
      normal sale exception to certain NUG power purchase agreements with a fair
      value
      of $13 million (included in “Other” in the table below) in accordance with
      guidance in DIG C20. The change in the fair value of commodity derivative
      contracts related to energy production during the three months and six months
      ended June 30, 2006 is summarized in the following table:





**Three
                Months Ended**
            
            **Six
                Months Ended****Increase
                (Decrease) in the Fair Value**
            **June
                30, 2006**
            
            **June
                30, 2006****of
                Commodity Derivative Contracts**
            **Non-Hedge**
            
            **Hedge**
            
            **Total**
            
            **Non-Hedge**
            
            **Hedge**
            
            **Total*****(In
                millions)*****Change
                in the Fair Value of****Commodity
                Derivative Contracts:**Outstanding
                net liability at beginning of period
            $
            (1,129
            )
            $
            (5
            )
            $
            (1,134
            )
            $
            (1,170
            )
            $
            (3
            )
            $
            (1,173
            )New
                contract
                value when entered
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Additions/change
                in value of existing contracts
            
            (17
            )
            
            (3
            )
            
            (20
            )
            
            (30
            )
            
            (10
            )
            
            (40
            )Change
                in
                techniques/assumptions
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Settled
                contracts
            
            78
            
            
            4
            
            
            82
            
            
            132
            
            
            9
            
            
            141Other
            
            (13
            )
            
            -
            
            
            (13
            )
            
            (13
            )
            
            -
            
            
            (13
            )Outstanding
                net liability at end of period(1)
            
            (1,081
            )
            
            (4
            )
            
            (1,085
            )
            
            (1,081
            )
            
            (4
            )
            
            (1,085
            )**Non-commodity
                Net Liabilities at End of Period:**Interest
                Rate
                Swaps(2)
            
            -
            
            
            (25
            )
            
            (25
            )
            
            -
            
            
            (25
            )
            
            (25
            )**Net
                Liabilities - Derivative Contracts**
              **at
                End
                of Period**
            $
            (1,081
            )
            $
            (29
            )
            $
            (1,110
            )
            $
            (1,081
            )
            $
            (29
            )
            $
            (1,110
            )**Impact
                of Changes in Commodity Derivative Contracts****(3)**Income
                Statement effects (pre-tax)
            $
            (1
            )
            $
            -
            
            $
            (1
            )
            $
            (3
            )
            $
            -
            
            $
            (3
            )Balance
                Sheet
                effects:Other
                comprehensive income (pre-tax)
            $
            -
            
            $
            1
            
            $
            1
            
            $
            -
            
            $
            (1
            )
            $
            (1
            )Regulatory
                assets (net)
            $
            (62
            )
            $
            -
            
            $
            (62
            )
            $
            (105
            )
            $
            -
            
            $
            (105
            )





(1)  Includes
      $1,078 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.


53





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





**Balance
                Sheet Classification**
            
            **Non-Hedge**
            
            **Hedge**
            
            **Total*****(In
                millions)*****Current-**Other
                assets
            
            $
            1
            
            $
            1
            
            $
            2Other
                liabilities
            
            
            (6
            )
            
            (4
            )
            
            (10
            )**Non-Current-**Other
                deferred
                charges
            
            
            47
            
            
            29
            
            
            76Other
                noncurrent liabilities
            
            
            (1,123
            )
            
            (55
            )
            
            (1,178
            )Net
                liabilities
            
            $
            (1,081
            )
            $
            (29
            )
            $
            (1,110
            )





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





**Source
                of Information****-
                Fair
                Value by Contract Year**
            
            **2006**(1)
            
            **2007**
            
            **2008**
            
            **2009**
            
            **2010**
            
            **Thereafter**
            
            **Total*****(In
                millions)***Prices
                actively quoted(2)
            
            $
            (1
            )
            $
            (1
            )
            $
            -
            
            $
            -
            
            $
            -
            
            $
            -
            
            $
            (2
            )Other
                external
                sources(3)
            
            
            (144
            )
            
            (251
            )
            
            (220
            )
            
            -
            
            
            -
            
            
            -
            
            
            (615
            )Prices
                based
                on models
            
            
            -
            
            
            -
            
            
            -
            
            
            (161
            )
            
            (138
            )
            
            (169
            )
            
            (468
            )**Total****(4)**
            
            $
            (145
            )
            $
            (252
            )
            $
            (220
            )
            $
            (161
            )
            $
            (138
            )
            $
            (169
            )
            $
            (1,085
            )





(1)  For
      the last two
      quarters of 2006.


(2)  Exchange
      traded.


(3)  Broker
      quote
      sheets.


(4)
            Includes
                $1,078 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 June 30, 2006. Based on derivative contracts held as of
      June 30, 2006, an adverse 10% change in commodity prices would decrease net
      income by approximately $1 million during the next 12 months.





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





FirstEnergy
      utilizes
      fixed-for-floating interest rate swap agreements as part of its ongoing effort
      to manage the interest rate risk associated with its debt portfolio. These
      derivatives are treated as fair value hedges of fixed-rate, long-term debt
      issues - designed to protect against the risk of changes in the fair value
      of
      fixed-rate debt instruments when interest rates decrease. Swap maturities,
      call
      options, fixed interest rates and interest payment dates match those of the
      underlying obligations. During the first six months of 2006, FirstEnergy unwound
      swaps with a total notional amount of $350 million, for which FirstEnergy
      paid $1 million in cash. The loss will be recognized over the remaining
      maturity of each respective hedged security as increased interest expense.
      As of
      June 30, 2006, the debt underlying the $750 million outstanding notional
      amount of interest rate swaps had a weighted average fixed interest rate of
      5.74%, which the swaps have converted to a current weighted average variable
      rate of 6.68%.


54





**June
                30, 2006**
            
            **December
                31, 2005****Notional**
            
            **Maturity**
            
            **Fair**
            
            **Notional**
            
            **Maturity**
            
            **Fair****Interest
                Rate Swaps**
            
            **Amount**
            
            **Date**
            
            **Value**
            
            **Amount**
            
            **Date**
            
            **Value*****(In
                millions)***(Fair
                value
                hedges)
            
            $
            100
            
            $
            2008
            
            $
            (4
            )
            
            100
            
            $
            2008
            
            $
            (3
            )50
            
            
            2010
            
            
            (2
            )
            
            50
            
            
            2010
            
            
            --
            
            
            2011
            
            
            -
            
            
            50
            
            
            2011
            
            
            -300
            
            
            2013
            
            
            (17
            )
            
            450
            
            
            2013
            
            
            (4
            )150
            
            
            2015
            
            
            (16
            )
            
            150
            
            
            2015
            
            
            (9
            )-
            
            
            2016
            
            
            -
            
            
            150
            
            
            2016
            
            
            -50
            
            
            2025
            
            
            (4
            )
            
            50
            
            
            2025
            
            
            (1
            )100
            
            
            2031
            
            
            (11
            )
            
            100
            
            
            2031
            
            
            (5
            )$
            750
            
            
            
            
            $
            (54
            )
            $
            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 six months of 2006, FirstEnergy revised the tenor and timing of its
      financing plans, and in the second quarter terminated forward swaps with an
      aggregate notional value of $600 million concurrent with its subsidiaries
      issuing long-term debt. FirstEnergy received $41 million in cash related to
      the
      termination. The gain associated with the ineffective portion of the terminated
      hedges ($6 million) was recognized in earnings, with the remainder to be
      recognized over the terms of the respective forward swaps. As of June 30, 2006,
      FirstEnergy had outstanding forward swaps with an aggregate notional amount
      of
      $550 million and an aggregate fair value of $29 million.





**June
                30, 2006**
            
            **December
                31, 2005****Notional**
            
            **Maturity**
            
            **Fair**
            
            **Notional**
            
            **Maturity**
            
            **Fair****Forward
                Starting Swaps**
            
            **Amount**
            
            **Date**
            
            **Value**
            
            **Amount**
            
            **Date**
            
            **Value*****(In
                millions)***(Cash
                flow
                hedges)
            
            $
            25
            
            
            2015
            
            $
            1
            
            $
            25
            
            
            2015
            
            $
            -300
            
            
            2016
            
            
            14
            
            
            600
            
            
            2016
            
            
            250
            
            
            2017
            
            
            3
            
            
            25
            
            
            2017
            
            
            -125
            
            
            2018
            
            
            8
            
            
            275
            
            
            2018
            
            
            150
            
            
            2020
            
            
            3
            
            
            50
            
            
            2020
            
            
            -$
            550
            
            
            
            
            $
            29
            
            $
            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 June
      30, 2006 and December 31, 2005. A hypothetical 10% decrease in prices
      quoted by stock exchanges would result in a $111 million
      reduction in fair value as of June 30, 2006.





**CREDIT
      RISK**




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




FirstEnergy maintains credit policies with respect to its counterparties to
      manage overall credit risk. This includes performing independent risk
      evaluations, actively monitoring portfolio trends and using collateral and
      contract provisions to mitigate exposure. As part of its credit program,
      FirstEnergy aggressively manages the quality of its portfolio of energy
      contracts, evidenced by a current weighted average risk rating for energy
      contract counterparties of BBB (S&P). As of June 30, 2006, the largest
      credit concentration with one party (currently rated investment grade)
      represented 8.1% 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 June 30,
      2006.


55





**OUTLOOK**





***Regulatory
      Matters***





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





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





The
      Companies and
      ATSI recognize, as regulatory assets, costs which the FERC, PUCO, PPUC and
      NJBPU
      have authorized for recovery from customers in future periods or for which
      authorization is probable. Without the probability of such authorization, costs
      currently recorded as regulatory assets would have been charged to income as
      incurred. Regulatory assets that do not earn a current return totaled
      approximately $237 million as of June 30, 2006. The following table
      discloses the regulatory assets by company and by source:





**June
                30,**
            
            **December
                31,**
            
            **Increase****Regulatory
                Assets***
            
            **2006**
            
            **2005**
            
            **(Decrease)*****(In
                millions)***OE
            
            $
            756
            
            $
            775
            
            $
            (19
            )CEI
            
            
            859
            
            
            862
            
            
            (3
            )TE
            
            
            267
            
            
            287
            
            
            (20
            )JCP&L
            
            
            2,122
            
            
            2,227
            
            
            (105
            )Met-Ed
            
            
            359
            
            
            310
            
            
            49ATSI
            
            
            33
            
            
            25
            
            
            8Total
            
            $
            4,396
            
            $
            4,486
            
            $
            (90
            )





*
            Penn
                had net
                regulatory liabilities of approximately $59 million as of June 30,
                2006 and December 31, 2005. Penelec had net regulatory liabilities of
                approximately $135 million and $163 million as of June 30,
                2006 and December 31, 2005, respectively. These net regulatory liabilities
                are included in Other Noncurrent Liabilities on the Consolidated
                Balance
                Sheets.




Regulatory assets by source are as follows:





**June
                30,**
            
            **December
                31,**
            
            **Increase****Regulatory
                Assets By Source**
            
            **2006**
            
            **2005**
            
            **(Decrease)*****(In
                millions)***Regulatory
                transition costs
            
            $
            3,365
            
            $
            3,576
            
            $
            (211
            )Customer
                shopping incentives
            
            
            644
            
            
            884
            
            
            (240
            )Customer
                receivables for future income taxes
            
            
            219
            
            
            217
            
            
            2Societal
                benefits charge
            
            
            19
            
            
            29
            
            
            (10
            )Loss
                on
                reacquired debt
            
            
            40
            
            
            41
            
            
            (1
            )Employee
                postretirement benefits costs
            
            
            51
            
            
            55
            
            
            (4
            )Nuclear
                decommissioning, decontaminationand
                spent fuel
                disposal costs
            
            
            (124
            )
            
            (126
            )
            
            2Asset
                removal
                costs
            
            
            (163
            )
            
            (365
            )
            
            202Property
                losses and unrecovered plant costs
            
            
            24
            
            
            29
            
            
            (5
            )MISO/PJM
                transmission costs
            
            
            135
            
            
            91
            
            
            44Fuel
                costs -
                RCP
            
            
            51
            
            
            -
            
            
            51Distribution
                costs - RCP
            
            
            81
            
            
            -
            
            
            81JCP&L
                reliability costs
            
            
            19
            
            
            23
            
            
            (4
            )Other
            
            
            35
            
            
            32
            
            
            3Total
            
            $
            4,396
            
            $
            4,486
            
            $
            (90
            )


56


***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.




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




EPACT provides for the creation of an ERO to establish and enforce reliability
      standards for the bulk power system, subject to FERC 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. The ERO filing was noticed on April 7, 2006 and comments and reply
      comments were filed in May, June and July 2006. On July 20, 2006, the FERC
      certified NERC as the ERO to implement the provisions of Section 215 of the
      Federal Power Act. The FERC directed NERC to make a compliance filing within
      ninety days addressing such issues as the regional delegation
      agreements.


On April 4, 2006, NERC also submitted a filing with the FERC seeking approval
      of
      mandatory reliability standards. These reliability standards are based, with
      some modifications, on the current NERC Version O reliability standards with
      some additional standards. The reliability standards filing was noticed by
      the
      FERC on April 18, 2006. In that notice, the FERC announced its intent to issue
      a
      Notice of Proposed Rulemaking on the proposed reliability standards at a future
      date. On May 11, 2006, the FERC staff released a preliminary assessment that
      cited many deficiencies in the proposed reliability standards. The NERC and
      industry participants filed comments in response to the Staff’s preliminary
      assessment. The FERC held a technical conference on the proposed reliability
      standards on July 6, 2006. The chairman has indicated that the FERC intends
      to
      act on the proposed reliability standards by issuing a NOPR in September of
      this
      year. Interested parties will be given the opportunity to comment on the NOPR.
      NERC has requested an effective date of January 1, 2007 for the proposed
      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.




On May 2, 2006, the NERC Board of Trustees adopted eight new cyber security
      standards that replaced interim standards put in place in the wake of the
      September 11, 2001 terrorist attacks, and thirteen additional reliability
      standards. The security standards became effective on June 1, 2006, and the
      remaining standards will become effective throughout 2006 and 2007. NERC intends
      to file the standards with the FERC and relevant Canadian authorities for
      approval.


57





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 their RSP case with the PUCO. On August 5, 2004, the
      Ohio Companies accepted the RSP as modified and approved by the PUCO in an
      August 4, 2004 Entry on Rehearing, subject to a CBP. The RSP was intended to
      establish generation service rates beginning January 1, 2006, in response to
      the
      PUCO’s concerns about price and supply uncertainty following the end of the Ohio
      Companies' transition plan market development period. In October 2004, the
      OCC
      and NOAC filed appeals with the Supreme Court of Ohio to overturn the original
      June 9, 2004 PUCO order in the proceeding as well as the associated entries
      on
      rehearing. On September 28, 2005, the Supreme Court of Ohio heard oral arguments
      on the appeals. On May 3, 2006, the Supreme Court of Ohio issued an opinion
      affirming the PUCO's order with respect to the approval of the rate
      stabilization charge, approval of the shopping credits, the granting of interest
      on shopping credit incentive deferral amounts, and approval of the Ohio
      Companies’ financial separation plan. It remanded one matter back to the PUCO
      for further consideration of the issue as to whether the RSP, as adopted by
      the
      PUCO, provided for sufficient means for customer participation in the
      competitive marketplace. On May 12, 2006, the Ohio Companies filed a Motion
      for
      Reconsideration with the Supreme Court of Ohio which was denied by the Court
      on
      June 21, 2006. The RSP contained a provision that permitted the Ohio Companies
      to withdraw and terminate the RSP in the event that the PUCO, or the Supreme
      Court of Ohio, rejected all or part of the RSP. In such event, the Ohio
      Companies have 30 days from the final order or decision to provide notice of
      termination. On July 20, 2006 the Ohio Companies filed with the PUCO a Request
      to Initiate a Proceeding on Remand. In their Request, the Ohio Companies
      provided notice of termination to those provisions of the RSP subject to
      termination, subject to being withdrawn, and also set forth a framework for
      addressing the Supreme Court of Ohio’s findings on customer participation,
      requesting the PUCO to initiate a proceeding to consider the Ohio Companies’
proposal. If the PUCO approves a resolution to the issues raised by the Supreme
      Court of Ohio that is acceptable to the Ohio Companies, the Ohio Companies’
termination will be withdrawn and considered to be null and void. Separately,
      the OCC and NOAC also submitted to the PUCO on July 20, 2006 a conceptual
      proposal dealing with the issue raised by the Supreme Court of Ohio. On July
      26,
      2006, the PUCO issued an Entry acknowledging the July 20, 2006 filings of the
      Ohio Companies and the OCC and NOAC, and giving the Ohio Companies 45 days
      to
      file a plan in a new docket to address the Court’s concern.




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





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





58




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
            
            $
            177
            
            $
            95
            
            $
            86
            
            $
            3582007
            
            
            180
            
            
            113
            
            
            90
            
            
            3832008
            
            
            208
            
            
            130
            
            
            111
            
            
            4492009
            
            
            -
            
            
            211
            
            
            -
            
            
            2112010
            
            
            -
            
            
            266
            
            
            -
            
            
            266**Total
                Amortization**
            
            **$**
            **565**
            
            **$**
            **815**
            
            **$**
            **287**
            
            **$**
            **1,667**




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





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




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




On December 30, 2004, the Ohio Companies filed with the PUCO two
      applications related to the recovery of transmission and ancillary service
      related costs. The first application sought recovery of these costs beginning
      January 1, 2006. The Ohio Companies requested that these costs be recovered
      through a rider that would be effective on January 1, 2006 and adjusted
      each July 1 thereafter. The parties reached a settlement agreement that was
      approved by the PUCO on August 31, 2005. The incremental transmission and
      ancillary service revenues recovered from January 1 through June 30, 2006
      were approximately $61 million. That amount included the recovery of a
      portion of the 2005 deferred MISO expenses as described below. On May 1,
      2006, the Ohio Companies filed a modification to the rider to determine revenues
      ($141 million) from July 2006 through June 2007.


59




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





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





***Pennsylvania***




As of June 30, 2006, Met-Ed's and Penelec's regulatory deferrals pursuant to
      the
      1998 Restructuring Settlement (including the Phase 2 Proceedings) and the
      FirstEnergy/GPU Merger Settlement Stipulation were $335 million and
      $57 million, respectively. Penelec's $57 million is subject to the
      pending resolution of taxable income issues associated with NUG trust fund
      proceeds. The PPUC is reviewing a January 2006 change in Met-Ed’s and Penelec’s
      NUG purchase power stranded cost accounting methodology. If the PPUC orders
      Met-Ed and Penelec to reverse the change in accounting methodology, this would
      result in a pre-tax loss of $10.3 million for Met-Ed.





On
      January 12,
      2005, Met-Ed and Penelec filed, before the PPUC, a request for deferral of
      transmission-related costs beginning January 1, 2005. The OCA, OSBA, OTS,
      MEIUG, PICA, Allegheny Electric Cooperative and Pennsylvania Rural Electric
      Association all intervened in the case. Met-Ed and Penelec sought to consolidate
      this proceeding (and modified their request to provide deferral of 2006
      transmission-related costs only) with the comprehensive rate filing they made
      on
      April 10, 2006 as described below. On May 4, 2006, the PPUC approved
      the modified request. Accordingly, Met-Ed and Penelec have deferred
      approximately $46 million and $12 million, respectively, representing
      transmission costs that were incurred from January 1, 2006 through June 30,
      2006. On June 5, 2006, the OCA filed before the Commonwealth Court a
      petition for review of the PPUC's approval of the deferral. On July 12, 2006
      the
      Commonwealth Court granted the PPUC’s motion to quash the OCA’s appeal. The
      ratemaking treatment of the deferrals will be determined in the comprehensive
      rate filing proceeding discussed further below.




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;


60


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




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





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





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





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





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 CBP as the amount of supply provided under the existing
      FES
      agreement is phased out in accordance with the April 7, 2006 Tolling
      Agreement described above. Met-Ed
      and Penelec
      also requested approval of the January 12, 2005 petition for the deferral
      of transmission-related costs discussed above, but only for those costs incurred
      during 2006. In this rate filing, Met-Ed and Penelec also requested recovery
      of
      annual transmission and related costs incurred on or after January 1, 2007,
      plus the amortized portion of 2006 costs over a ten-year period, along with
      applicable carrying charges, through an adjustable rider similar to that
      implemented in Ohio. Changes in the
      recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs
      are
      also included in the filing. The filing contemplates a reduction in distribution
      rates for Met-Ed of $37 million annually and an increase in distribution
      rates for Penelec of $20 million annually. The PPUC suspended the effective
      date (June 10, 2006) of the rate changes for seven months after the filing
      as permitted under Pennsylvania law. If
        the PPUC adopts the overall positions taken in the intervenors’ testimony as
        filed, this would have a material adverse effect on the financial statements
        of
        FirstEnergy, Met-Ed and Penelec.





Under
      Pennsylvania's
      electric competition law, Penn is required to secure generation supply for
      customers who do not choose alternative suppliers for their electricity. On
      October 11, 2005, Penn filed a plan with the PPUC to secure electricity
      supply for its customers at set rates following the end of its transition period
      on December 31, 2006. Penn recommended that the RFP process cover the
      period January 1, 2007 through May 31, 2008. To the extent that an
      affiliate of Penn supplies a portion of the PLR load included in the RFP,
      authorization to make the affiliate sale must be obtained from the FERC.
      Hearings before the PPUC were held on January 10, 2006 with main briefs
      filed on January 27, 2006 and reply briefs filed on February 3, 2006.
      On February 16, 2006, the ALJ issued a Recommended Decision to adopt Penn's
      RFP process with modifications. On April 20, 2006, the PPUC approved the
      Recommended Decision with additional modifications to use an RFP process to
      obtain Penn's power supply requirements after 2006 through two separate
      solicitations. An initial solicitation was held for Penn in May 2006 with all
      tranches fully subscribed. On June 2, 2006, the PPUC approved the bid results
      for the first solicitation. On July 18, 2006, the second PLR solicitation was
      held for Penn. The tranches for the Residential Group and Small Commercial
      Group
      were fully subscribed. However, supply was only acquired for three of the five
      tranches for the Large Commercial Group. On July 20, 2006, the PPUC approved
      the
      submissions for the second bid. A residual solicitation is scheduled to be
      held
      on August 15, 2006 for the two remaining Large Commercial Group tranches.
      Acceptance of the winning bids is subject to approval by the PPUC.


61





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





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





***New
      Jersey***





JCP&L
      is
      permitted to defer for future collection from customers the amounts by which
      its
      costs of supplying BGS to non-shopping customers and costs incurred under NUG
      agreements exceed amounts collected through BGS and NUGC rates and market sales
      of NUG energy and capacity. As of June 30, 2006, the accumulated deferred cost
      balance totaled approximately $638 million. New Jersey law allows for
      securitization of JCP&L's deferred balance upon application by JCP&L and
      a determination by the NJBPU that the conditions of the New Jersey restructuring
      legislation are met. On February 14, 2003, JCP&L filed for approval to
      securitize the July 31, 2003 deferred balance. On June 8, 2006, the NJBPU
      approved JCP&L’s request to issue securitization bonds associated with BGS
      stranded cost deferrals. On August 4, 2006, JCP&L Transition Funding II, a
      wholly owned subsidiary of JCP&L, secured pricing on the issuance of $182
      million of transition bonds with a weighted average interest rate of
      5.5%.





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 23, 2006, JCP&L filed updated data reflecting
      actual amounts through December 31, 2005 of $154 million of cost
      incurred since July 31, 2003. 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 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
      last of the quarterly reliability reports was submitted on June 12, 2006. As
      of
      June 30, 2006, 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 repeal
      of
      PUHCA pursuant to the EPACT. An NJBPU proposed rulemaking to address the issues
      was published in the NJ Register on December 19, 2005. The proposal would
      prevent a holding company that owns a gas or electric public utility from
      investing more than 25% of the combined assets of its utility and
      utility-related subsidiaries into businesses unrelated to the utility industry.
      A public hearing was held on February 7, 2006 and comments were submitted
      to the NJBPU. 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. With the approval
      of the NJBPU Staff, the affected utilities jointly submitted an alternative
      proposal on June 1, 2006. Comments on the alternative proposal were submitted
      on
      June 15, 2006. JCP&L is unable to predict the outcome of this
      proposal.





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





***FERC
      Matters***





On
      November 18,
      2004, the FERC issued an order eliminating the RTOR for transmission service
      between the MISO and PJM regions. The FERC also ordered the MISO, PJM and the
      transmission owners within MISO and PJM to submit compliance filings containing
      a SECA mechanism to recover lost RTOR revenues during a 16-month transition
      period from load serving entities. The FERC issued orders in 2005 setting the
      SECA for hearing. ATSI, JCP&L, Met-Ed, Penelec, and FES continue to be
      involved in the FERC hearings concerning the calculation and imposition of
      the
      SECA charges. The hearing was held in May 2006. Initial briefs were submitted
      on
      June 9, 2006, and reply briefs were filed on June 27, 2006. The FERC has
      ordered the Presiding Judge to issue an initial decision by August 11,
      2006.


62





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 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 $33 million
      deferred as of June 30, 2006). On March 28, 2006, ATSI and MISO filed with
      the FERC a request to modify ATSI’s Attachment O formula rate to include
      revenue requirements associated with recovery of deferred VMEP costs over a
      five-year period. The requested effective date to begin recovery was
      June 1, 2006. Various parties filed comments responsive to the
      March 28, 2006 submission. The FERC conditionally approved the filing on
      May 22, 2006, subject to a compliance filing that ATSI made on June 13, 2006.
      A
      request for rehearing of the FERC’s May 22, 2006 Order was filed by a party,
      which ATSI answered. On July 21, 2006, the FERC issued an order stating that
      it
      needs more time to consider the matter. In light of that order, there is no
      time
      period by which the FERC must act on the pending rehearing request. On July
      14,
      2006, the FERC accepted the ATSI’s June 13, 2006 compliance filing. The
      estimated annual revenues to ATSI from the VMEP cost recovery is
      $12 million.





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





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




On
      November 1, 2005, FES filed two power sales agreements for approval with
      the FERC. One power sales agreement provided for FES to provide the PLR
      requirements of the Ohio Companies at a price equal to the retail generation
      rates approved by the PUCO for a period of three years beginning January 1,
      2006. The Ohio Companies will be relieved of their obligation to obtain PLR
      power requirements from FES if the Ohio CBP results in a lower price for retail
      customers. A similar power sales agreement between FES and Penn permits Penn
      to
      obtain its PLR power requirements from FES at a fixed price equal to the retail
      generation price during 2006. 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 through two separate solicitations. An initial solicitation was
      held
      for Penn in May 2006 with all tranches fully subscribed. On June 2, 2006, the
      PPUC approved the bid results for the first solicitation. On July 18, 2006,
      the
      second PLR solicitation was held for Penn. The tranches for the Residential
      Group and Small Commercial Group were fully subscribed. However, supply was
      only
      acquired for three of the five tranches for the Large Commercial Group. On
      July
      20, 2006, the PPUC approved the submission for the second bid. A residual
      solicitation is scheduled to be held on August 15, 2006 for the two remaining
      Large Commercial Group tranches. Acceptance of the winning bids is subject
      to
      approval by the PPUC.








63





On
      December 29,
      2005, the FERC issued an order setting the two power sales agreements for
      hearing. The order criticized the Ohio CBP, and required FES to submit
      additional evidence in support of the reasonableness of the prices charged
      in
      the power sales agreements. A pre-hearing conference was held on
      January 18, 2006 to determine the hearing schedule in this case. Under
      the procedural schedule, aproved in this case, FES expected an initial decision
      to be issued in late January 2007. However, on July 14, 2006, the Chief
      Judge granted the joint motion of FES and the Trial Staff to appoint a
      settlement judge in this proceeding. The procedural schedule has been suspended
      pending negotiations among the parties.





***Environmental
      Matters***





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





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





*Clean
      Air Act
      Compliance*





FirstEnergy
      is
      required to meet federally approved SO 2 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.





The
      EPA Region 5
      issued a Finding of Violation and NOV to the Bay Shore Power Plant dated June
      15, 2006 alleging violations to various sections of the Clean Air Act. A meeting
      has been scheduled for August 8, 2006 to discuss the alleged violations with
      the
      EPA.





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.





*National
      Ambient
      Air Quality Standards*





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


64


*Mercury
      Emissions*





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





The
      model rules for
      both CAIR and CAMR contemplate an input-based methodology to allocate allowances
      to affected facilities. Under this approach, allowances would be allocated
      based
      on the amount of fuel consumed by the affected sources. FirstEnergy would prefer
      an output-based generation-neutral methodology in which allowances are allocated
      based on megawatts of power produced. Since 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.





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





*W.
      H. Sammis
      Plant*





In
      1999 and 2000,
      the EPA issued NOV or Compliance Orders to nine utilities alleging violations
      of
      the Clean Air Act based on operation and maintenance of 44 power plants,
      including the W. H. Sammis Plant, which was owned at that time by OE and Penn.
      In addition, the DOJ filed eight civil complaints against various investor-owned
      utilities, including a complaint against OE and Penn in the U.S. District Court
      for the Southern District of Ohio. These cases are referred to as New Source
      Review cases. On March 18, 2005, OE and Penn announced that they had
      reached a settlement with the EPA, the DOJ and three states (Connecticut, New
      Jersey, and New York) that resolved all issues related to the W. H. Sammis
      Plant
      New Source Review litigation. This settlement agreement was approved by the
      Court on July 11, 2005, and requires reductions of NO X and SO 2 emissions at the W.
      H. Sammis Plant and other coal fired plants through the installation of
      pollution control devices and provides for stipulated penalties for failure
      to
      install and operate such pollution controls in accordance with that agreement.
      Consequently, if FirstEnergy fails to install such pollution control devices,
      for any reason, including, but not limited to, the failure of any third-party
      contractor to timely meet its delivery obligations for such devices, FirstEnergy
      could be exposed to penalties under the settlement agreement. Capital
      expenditures necessary to meet those requirements are currently estimated to
      be
      $1.5 billion (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 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.





*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.


65





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 June
      30,
      2006, based on estimates of the total costs of cleanup, the Companies'
      proportionate responsibility for such costs and the financial ability of other
      unaffiliated entities to pay. In addition, JCP&L has accrued liabilities for
      environmental remediation of former manufactured gas plants in New Jersey.
      Those
      costs are being recovered by JCP&L through a non-bypassable SBC. Total
      liabilities of approximately $70 million have been accrued through June 30,
      2006.




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





***Other
      Legal Proceedings***





*Power
      Outages
      and Related Litigation*





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


66





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. Three other pending PUCO complaint cases were filed by various
      insurance carriers either in their own name as subrogees or in the name of
      their
      insured. In each of these three cases, the carrier seeks reimbursement from
      various FirstEnergy companies (and, in one case, from PJM, MISO and American
      Electric Power Company, Inc., as well) for claims paid to insureds for
      damages allegedly arising as a result of the loss of power on August 14,
      2003. The listed insureds in these cases, in many instances, are not customers
      of any FirstEnergy company. The sixth case involves the claim of a non-customer
      seeking reimbursement for losses incurred when its store was burglarized on
      August 14, 2003. FirstEnergy filed a Motion to Dismiss on June 13, 2006. It
      is currently expected that this case will be summarily dismissed, although
      the
      Motion is still pending. 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 as a defendant; ruled that
      the
      U.S.-Canada Power System Outage Task Force Report was not admissible into
      evidence; and gave the plaintiffs additional time to amend their complaints
      to
      otherwise comply with the PUCO’s underlying order. Also, most
      complainants, along with the FirstEnergy companies, filed applications for
      rehearing with the PUCO over various rulings contained in the March 7, 2006
      order. On April 26, 2006, the PUCO granted rehearing to allow the insurance
      company claimants, as insurers, to prosecute their claims in their name so
      long
      as they also identify the underlying insured entities and the Ohio utilities
      that provide their service. The PUCO denied all other motions for rehearing.
      The
      plaintiffs in each case have since filed an amended complaint and the named
      FirstEnergy companies have answered and also have filed a motion to dismiss
      each
      action. These motions are pending. Additionally, on June 23, 2006, one of the
      insurance carrier complainants filed an appeal with the Ohio Supreme Court
      over
      the PUCO’s denial of their motion for rehearing on the issue of the
      admissibility of the Task Force Report and the dismissal of FirstEnergy Corp.
      as
      a respondent. Briefing is expected to be completed on this appeal by
      mid-September. It is unknown when the Supreme Court will rule on the appeal.
      No
      estimate of potential liability is available for any of these cases.





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.
      FirstEnergy's motion to dismiss the matter was denied on June 2, 2006.
      FirstEnergy has since filed an appeal, which is pending. A responsive pleading
      to this matter has been filed. Also, the complaint has been amended to include
      an additional party. No estimate of potential liability has been undertaken
      in
      this matter.





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





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





*Nuclear
      Plant
      Matters*





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


67





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.





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 the now repealed PUHCA. Concurrent with
      this
      notification, FirstEnergy received a subpoena asking for background documents
      and documents related to the restatements and Davis-Besse issues. On
      December 30, 2004, FirstEnergy received a subpoena asking for documents
      relating to issues raised during the SEC's PUHCA examination. On August 24,
      2005, additional information was requested regarding Davis-Besse related
      disclosures, which FirstEnergy has provided. FirstEnergy has cooperated fully
      with the informal inquiry and will continue to do so with the formal
      investigation.





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





68


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. Both filings were consolidated
      for hearing and decision described above. An adverse ruling could negatively
      affect full recovery of transition charges by the utility. Hearings on the
      matter were held in August 2005. Initial briefs from all parties were filed
      on
      September 22, 2005 and reply briefs were filed on October 14, 2005. On
      May 10, 2006, the PUCO issued its Opinion and Order dismissing the City’s
      complaint and approving the related tariffs, thus affirming OE’s entitlement to
      recovery of its transition charges. The City of Huron
      filed an application for rehearing of the PUCO’s decision on June 9, 2006
      and OE filed a memorandum in opposition to that application on June 19,
      2006. The PUCO denied the City’s application for rehearing on June 28, 2006. The
      City of Huron has 60 days from the denial of rehearing to appeal the PUCO’s
      decision.





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**





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





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


Step
                  1:
              Analyze
                  the
                  nature of the risks in the entityStep
                  2:
              Determine
                  the
                  purpose(s) for which the entity was created and determine the variability
                  the entity is designed to create and pass along to its interest
                  holders.
   After
        determining the variability to
        consider, the reporting enterprise can determine which interests are designed
        to
        absorb that variability. The guidance in this FSP is applied prospectively
        to
        all entities (including newly created entities) with which that enterprise
        first
        becomes involved and to all entities previously required to be analyzed under
        Interpretation 46(R) when a reconsideration event has occurred after July
        1,
        2006. FirstEnergy does not expect this Statement to have a material impact
        on
        its financial statements.





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





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


69





**SUBSEQUENT
      EVENTS**





**Pennsylvania
      Law Change**





On
      July 12, 2006,
      the Governor of Pennsylvania signed House Bill 859, which increases the net
      operating loss deduction allowed for the corporate net income tax from
      $2 million to $3 million, or the greater of 12.5% of taxable income.
      As a result, FirstEnergy expects to recognize a net operating loss benefit
      of
      $2.2 million (net of federal tax benefit) in the third quarter of
      2006.





**New
      Jersey
      Law Change**





On
      July 8, 2006, the
      Governor of New Jersey signed tax legislation that increased the current New
      Jersey Corporate Business tax by an additional 4% surtax, which increases the
      effective tax from 9% to 9.36%. This increase applies to JCP&L’s 2006
      through 2008 tax years and is not expected to have a material impact on
      FirstEnergy’s or JCP&L’s results of operations.


70


**OHIO
                      EDISON COMPANY****CONSOLIDATED
                      STATEMENTS OF INCOME AND COMPREHENSIVE INCOME****(Unaudited)****Three
                      Months Ended**
                  
                  **Six
                      Months Ended****June
                      30,**
                  
                  **June
                      30,****2006**
                  
                  **2005**
                  
                  **2006**
                  
                  **2005****STATEMENTS
                      OF INCOME**
                  
                  ***(In
                      thousands)*****REVENUES**
                  
                  $
                  573,092
                  
                  $
                  716,612
                  
                  $
                  1,159,295
                  
                  $
                  1,442,970**EXPENSES:**Fuel
                  
                  
                  2,821
                  
                  
                  12,006
                  
                  
                  5,772
                  
                  
                  23,922Purchased
                      power
                  
                  
                  293,033
                  
                  
                  227,507
                  
                  
                  576,053
                  
                  
                  474,097Nuclear
                      operating costs
                  
                  
                  43,506
                  
                  
                  92,607
                  
                  
                  84,590
                  
                  
                  188,260Other
                      operating costs
                  
                  
                  91,604
                  
                  
                  95,589
                  
                  
                  182,414
                  
                  
                  178,768Provision
                      for
                      depreciation
                  
                  
                  17,547
                  
                  
                  31,654
                  
                  
                  35,563
                  
                  
                  57,706Amortization
                      of regulatory assets
                  
                  
                  43,444
                  
                  
                  109,670
                  
                  
                  97,305
                  
                  
                  221,441Deferral
                      of
                      new regulatory assets
                  
                  
                  (42,083
                  )
                  
                  (39,026
                  )
                  
                  (78,323
                  )
                  
                  (63,821
                  )General
                      taxes
                  
                  
                  43,931
                  
                  
                  46,043
                  
                  
                  89,826
                  
                  
                  94,121Total
                      expenses
                  
                  
                  493,803
                  
                  
                  576,050
                  
                  
                  993,200
                  
                  
                  1,174,494**OPERATING
                      INCOME**
                  
                  
                  79,289
                  
                  
                  140,562
                  
                  
                  166,095
                  
                  
                  268,476**OTHER
                      INCOME (EXPENSE):**Investment
                      income
                  
                  
                  32,818
                  
                  
                  22,482
                  
                  
                  65,860
                  
                  
                  43,089Miscellaneous
                      expense
                  
                  
                  (1,001
                  )
                  
                  (2,161
                  )
                  
                  (804
                  )
                  
                  (23,897
                  )Interest
                      expense
                  
                  
                  (17,366
                  )
                  
                  (21,402
                  )
                  
                  (35,598
                  )
                  
                  (39,605
                  )Capitalized
                      interest
                  
                  
                  643
                  
                  
                  3,006
                  
                  
                  1,134
                  
                  
                  5,241Subsidiary's
                      preferred stock dividend requirements
                  
                  
                  (155
                  )
                  
                  (738
                  )
                  
                  (311
                  )
                  
                  (1,378
                  )Total
                      other
                      income (expense)
                  
                  
                  14,939
                  
                  
                  1,187
                  
                  
                  30,281
                  
                  
                  (16,550
                  )**INCOME
                      TAXES**
                  
                  
                  35,019
                  
                  
                  94,653
                  
                  
                  73,337
                  
                  
                  148,073**NET
                      INCOME**
                  
                  
                  59,209
                  
                  
                  47,096
                  
                  
                  123,039
                  
                  
                  103,853**PREFERRED
                      STOCK DIVIDEND REQUIREMENTS AND****REDEMPTION
                      PREMIUM**
                  
                  
                  3,587
                  
                  
                  658
                  
                  
                  4,246
                  
                  
                  1,317**EARNINGS
                      ON COMMON STOCK**
                  
                  $
                  55,622
                  
                  $
                  46,438
                  
                  $
                  118,793
                  
                  $
                  102,536**STATEMENTS
                      OF COMPREHENSIVE INCOME****NET
                      INCOME**
                  
                  $
                  59,209
                  
                  $
                  47,096
                  
                  $
                  123,039
                  
                  $
                  103,853**OTHER
                      COMPREHENSIVE INCOME (LOSS):**Unrealized
                      gain (loss) on available for sale securities
                  
                  
                  (4,063
                  )
                  
                  (12,960
                  )
                  
                  1,672
                  
                  
                  (15,677
                  )Income
                      tax
                      expense (benefit) related to othercomprehensive
                      income
                  
                  
                  (1,466
                  )
                  
                  (4,546
                  )
                  
                  603
                  
                  
                  (5,670
                  )Other
                      comprehensive income (loss), net of tax
                  
                  
                  (2,597
                  )
                  
                  (8,414
                  )
                  
                  1,069
                  
                  
                  (10,007
                  )**TOTAL
                      COMPREHENSIVE INCOME**
                  
                  $
                  56,612
                  
                  $
                  38,682
                  
                  $
                  124,108
                  
                  $
                  93,846The
                      preceding
                      Notes to Consolidated Financial Statements as they relate to
                      Ohio Edison
                      Company are an integral part of these statements.
   71
  **OHIO
                        EDISON COMPANY****CONSOLIDATED
                        BALANCE SHEETS****(Unaudited)****June
                        30,**
                    
                    **December
                        31,****2006**
                    
                    
                    **2005*****(In
                        thousands)*****ASSETS****CURRENT
                        ASSETS:**Cash
                        and cash
                        equivalents
                    
                    $
                    545,292
                    
                    
                    
                    $
                    929Receivables-Customers
                        (less accumulated provisions of $8,627,000 and $7,619,000,
                        respectively,for
                        uncollectible accounts)
                    
                    
                    250,079
                    
                    
                    
                    
                    290,887Associated
                        companies
                    
                    
                    165,501
                    
                    
                    
                    
                    187,072Other
                        (less
                        accumulated provisions of $52,000 and $4,000,
                        respectively,for
                        uncollectible accounts)
                    
                    
                    11,491
                    
                    
                    
                    
                    15,327Notes
                        receivable from associated companies
                    
                    
                    506,337
                    
                    
                    
                    
                    536,629Prepayments
                        and other
                    
                    
                    22,794
                    
                    
                    
                    
                    93,1291,501,494
                    
                    
                    
                    
                    1,123,973**UTILITY
                        PLANT:**In
                        service
                    
                    
                    2,558,212
                    
                    
                    
                    
                    2,526,851Less
                        -
                        Accumulated provision for depreciation
                    
                    
                    996,261
                    
                    
                    
                    
                    984,4631,561,951
                    
                    
                    
                    
                    1,542,388Construction
                        work in progress
                    
                    
                    63,277
                    
                    
                    
                    
                    58,7851,625,228
                    
                    
                    
                    
                    1,601,173**OTHER
                        PROPERTY AND INVESTMENTS:**Long-term
                        notes receivable from associated companies
                    
                    
                    1,676,228
                    
                    
                    
                    
                    1,758,776Investment
                        in
                        lease obligation bonds
                    
                    
                    310,285
                    
                    
                    
                    
                    325,729Nuclear
                        plant
                        decommissioning trusts
                    
                    
                    106,360
                    
                    
                    
                    
                    103,854Other
                    
                    
                    40,968
                    
                    
                    
                    
                    44,2102,133,841
                    
                    
                    
                    
                    2,232,569**DEFERRED
                        CHARGES AND OTHER ASSETS:**Regulatory
                        assets
                    
                    
                    756,481
                    
                    
                    
                    
                    774,983Prepaid
                        pension costs
                    
                    
                    227,815
                    
                    
                    
                    
                    224,813Property
                        taxes
                    
                    
                    52,897
                    
                    
                    
                    
                    52,875Unamortized
                        sale and leaseback costs
                    
                    
                    52,637
                    
                    
                    
                    
                    55,139Other
                    
                    
                    26,988
                    
                    
                    
                    
                    31,7521,116,818
                    
                    
                    
                    
                    1,139,562$
                    6,377,381
                    
                    
                    
                    $
                    6,097,277**LIABILITIES
                        AND CAPITALIZATION****CURRENT
                        LIABILITIES:**Currently
                        payable long-term debt
                    
                    $
                    225,625
                    
                    
                    
                    $
                    280,255Short-term
                        borrowings-Associated
                        companies
                    
                    
                    2,161
                    
                    
                    
                    
                    57,715Other
                    
                    
                    22,431
                    
                    
                    
                    
                    143,585Accounts
                        payable-Associated
                        companies
                    
                    
                    123,912
                    
                    
                    
                    
                    172,511Other
                    
                    
                    12,312
                    
                    
                    
                    
                    9,607Accrued
                        taxes
                    
                    
                    173,248
                    
                    
                    
                    
                    163,870Accrued
                        interest
                    
                    
                    7,150
                    
                    
                    
                    
                    8,333Other
                    
                    
                    64,098
                    
                    
                    
                    
                    61,726630,937
                    
                    
                    
                    
                    897,602**CAPITALIZATION:**Common
                        stockholder's equity-Common
                        stock,
                        without par value, authorized 175,000,000 shares - 100 shares
                        outstanding
                    
                    
                    2,296,525
                    
                    
                    
                    
                    2,297,253Accumulated
                        other comprehensive income
                    
                    
                    5,163
                    
                    
                    
                    
                    4,094Retained
                        earnings
                    
                    
                    285,434
                    
                    
                    
                    
                    200,844Total
                        common
                        stockholder's equity
                    
                    
                    2,587,122
                    
                    
                    
                    
                    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
                    
                    
                    1,521,863
                    
                    
                    
                    
                    1,019,6424,184,055
                    
                    
                    
                    
                    3,596,903**NONCURRENT
                        LIABILITIES:**Accumulated
                        deferred income taxes
                    
                    
                    747,568
                    
                    
                    
                    
                    769,031Accumulated
                        deferred investment tax credits
                    
                    
                    22,307
                    
                    
                    
                    
                    24,081Asset
                        retirement obligation
                    
                    
                    85,578
                    
                    
                    
                    
                    82,527Retirement
                        benefits
                    
                    
                    294,755
                    
                    
                    
                    
                    291,051Deferred
                        revenues - electric service programs
                    
                    
                    104,855
                    
                    
                    
                    
                    121,693Other
                    
                    
                    307,326
                    
                    
                    
                    
                    314,3891,562,389
                    
                    
                    
                    
                    1,602,772**COMMITMENTS
                        AND CONTINGENCIES (Note 10)**$
                    6,377,381
                    
                    
                    
                    $
                    6,097,277The
                        preceding
                        Notes to Consolidated Financial Statements as they relate
                        to Ohio Edison
                        Company are an integral part of these balance
                        sheets.
 72
  **OHIO
                      EDISON COMPANY****CONSOLIDATED
                      STATEMENTS OF CASH FLOWS****(Unaudited)****Six
                      Months Ended****June
                      30,****2006**
                  
                  **2005*****(In
                      thousands)*****CASH
                      FLOWS FROM OPERATING ACTIVITIES:**Net
                      income
                  
                  $
                  123,039
                  
                  $
                  103,853Adjustments
                      to
                      reconcile net income to net cash from operating activities
                      -Provision
                      for
                      depreciation
                  
                  
                  35,563
                  
                  
                  57,706Amortization
                      of regulatory assets
                  
                  
                  97,305
                  
                  
                  221,441Deferral
                      of
                      new regulatory assets
                  
                  
                  (78,323
                  )
                  
                  (63,821
                  )Nuclear
                      fuel
                      and lease amortization
                  
                  
                  (11,337
                  )
                  
                  18,663Amortization
                      of lease costs
                  
                  
                  (4,334
                  )
                  
                  (2,952
                  )Deferred
                      income taxes and investment tax credits, net
                  
                  
                  (17,351
                  )
                  
                  (5,142
                  )Accrued
                      compensation and retirement benefits
                  
                  
                  930
                  
                  
                  3,504Decrease
                      (increase) in operating assets -Receivables
                  
                  
                  66,215
                  
                  
                  77,745Materials
                      and
                      supplies
                  
                  
                  -
                  
                  
                  (18,149
                  )Prepayments
                      and other current assets
                  
                  
                  70,335
                  
                  
                  (7,220
                  )Increase
                      (decrease) in operating liabilities -Accounts
                      payable
                  
                  
                  (45,894
                  )
                  
                  (85,227
                  )Accrued
                      taxes
                  
                  
                  9,378
                  
                  
                  19,078Accrued
                      interest
                  
                  
                  (1,183
                  )
                  
                  (791
                  )Electric
                      service prepayment programs
                  
                  
                  (16,838
                  )
                  
                  132,151Other
                  
                  
                  (8,772
                  )
                  
                  12,876Net
                      cash
                      provided from operating activities
                  
                  
                  218,733
                  
                  
                  463,715**CASH
                      FLOWS FROM FINANCING ACTIVITIES:**New
                      Financing
                      -Long-term
                      debt
                  
                  
                  599,778
                  
                  
                  146,450Short-term
                      borrowings, net
                  
                  
                  -
                  
                  
                  47,442Redemptions
                      and Repayments -Preferred
                      stock
                  
                  
                  -
                  
                  
                  (37,750
                  )Long-term
                      debt
                  
                  
                  (146,893
                  )
                  
                  (260,508
                  )Short-term
                      borrowings, net
                  
                  
                  (176,708
                  )
                  
                  -Dividend
                      Payments -Common
                      stock
                  
                  
                  (35,000
                  )
                  
                  (177,000
                  )Preferred
                      stock
                  
                  
                  (1,317
                  )
                  
                  (1,317
                  )Net
                      cash
                      provided from (used for) financing activities
                  
                  
                  239,860
                  
                  
                  (282,683
                  )**CASH
                      FLOWS FROM INVESTING ACTIVITIES:**Property
                      additions
                  
                  
                  (49,659
                  )
                  
                  (121,458
                  )Proceeds
                      from
                      nuclear decommissioning trust fund sales
                  
                  
                  30,269
                  
                  
                  122,374Investments
                      in
                      nuclear decommissioning trust funds
                  
                  
                  (30,961
                  )
                  
                  (138,144
                  )Loan
                      repayments from (loans to) associated companies, net
                  
                  
                  112,840
                  
                  
                  (58,540
                  )Other
                  
                  
                  23,281
                  
                  
                  14,789Net
                      cash
                      provided from (used for) investing activities
                  
                  
                  85,770
                  
                  
                  (180,979
                  )Net
                      increase
                      in cash and cash equivalents
                  
                  
                  544,363
                  
                  
                  53Cash
                      and cash
                      equivalents at beginning of period
                  
                  
                  929
                  
                  
                  1,230Cash
                      and cash
                      equivalents at end of period
                  
                  $
                  545,292
                  
                  $
                  1,283The
                      preceding
                      Notes to Consolidated Financial Statements as they relate to
                      Ohio Edison
                      Company are an integral part of these
                      statements.
 73
  
 
 ***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 June 30, 2006, and the related consolidated statements
        of
        income and comprehensive income for each of the three-month and six-month
        periods ended June 30, 2006 and 2005 and the consolidated statement of cash
        flows for the six-month period ended June 30, 2006 and 2005. These interim
        financial statements are the responsibility of the Company’s
        management.
 
 We
        conducted our
        review in accordance with the standards of the Public Company Accounting
        Oversight Board (United States). A review of interim financial information
        consists principally of applying analytical procedures and making inquiries
        of
        persons responsible for financial and accounting matters. It is substantially
        less in scope than an audit conducted in accordance with the standards of
        the
        Public Company Accounting Oversight Board, the objective of which is the
        expression of an opinion regarding the financial statements taken as a whole.
        Accordingly, we do not express such an opinion.
 
 Based
        on our review,
        we are not aware of any material modifications that should be made to the
        accompanying consolidated interim financial statements for them to be in
        conformity with accounting principles generally accepted in the United States
        of
        America.
 
 We
        have previously
        audited, in accordance with the standards of the Public Company Accounting
        Oversight Board (United States), the consolidated balance sheet as of December
        31, 2005, and the related consolidated statements of income, capitalization,
        common stockholder’s equity, preferred stock, cash flows and taxes for the year
        then ended (not presented herein), and in our report [which contained references
        to the Company’s change in its method of accounting for asset retirement
        obligations as of January 1, 2003 and conditional asset retirement obligations
        as of December 31, 2005 as discussed in Note 2(G) and Note 11 to those
        consolidated financial statements] dated February 27, 2006, we expressed
        an
        unqualified opinion on those consolidated financial statements. In our opinion,
        the information set forth in the accompanying consolidated balance sheet
        as of
        December 31, 2005, is fairly stated in all material respects in relation
        to the
        consolidated balance sheet from which it has been derived.
 
 
 
 
 PricewaterhouseCoopers
        LLP
 Cleveland,
        Ohio
 August
        4,
        2006
 
 
  74
  **OHIO
        EDISON
        COMPANY**
 
 **MANAGEMENT’S
        DISCUSSION AND ANALYSIS OF**
 **RESULTS
        OF
        OPERATIONS AND FINANCIAL CONDITION**
 
 
 OE
        is a wholly owned
        electric utility subsidiary of FirstEnergy. OE and its wholly owned subsidiary,
        Penn, conduct business in portions of Ohio and Pennsylvania, providing regulated
        electric distribution services. Penn’s rate restructuring plan and its
        associated transition charge revenue recovery was completed in 2005. The
        OE
        Companies also provide generation services to those customers electing to
        retain
        the OE Companies as their power supplier. Power supply requirements of the
        OE
        Companies are provided by FES - an affiliated
        company.
 
 **FirstEnergy
        Intra-System Generation Asset Transfers**
  In
        2005, the Ohio Companies and Penn entered into certain agreements implementing
        a
        series of intra-system generation asset transfers that were completed in
        the
        fourth quarter of 2005. The asset transfers resulted in the respective undivided
        ownership interests of the Ohio Companies and Penn in FirstEnergy’s nuclear and
        non-nuclear generation assets being owned by NGC and FGCO, respectively.
        The
        generating plant interests transferred did not include OE's leasehold interests
        in certain of the plants that are currently subject to sale and leaseback
        arrangements with non-affiliates.
  On
        October 24, 2005, the OE Companies completed the intra-system transfer of
        non-nuclear generation assets to FGCO. Prior to the transfer, FGCO, as lessee
        under a Master Facility Lease with the Ohio Companies and Penn, leased, operated
        and maintained the non-nuclear generation assets that it now owns. The asset
        transfers were consummated pursuant to FGCO's purchase option under the Master
        Facility Lease.
  On
        December 16, 2005, the OE Companies completed the intra-system transfer of
        their ownership interests in the nuclear generation assets to NGC through
        an
        asset spin-off in the form of a dividend. FENOC continues to operate and
        maintain the nuclear generation assets.
  These transactions were undertaken pursuant to the Ohio Companies’ and Penn’s
        restructuring plans that were approved by the PUCO and the PPUC, respectively,
        under applicable Ohio and Pennsylvania electric utility restructuring
        legislation. Consistent with the restructuring plans, generation assets that
        had
        been owned by the Ohio Companies and Penn were required to be separated from
        the
        regulated delivery business of those companies through transfer to a separate
        corporate entity. The transactions essentially completed the divestitures
        contemplated by the restructuring plans by transferring the ownership interests
        to NGC and FGCO without impacting the operation of the plants.
  The
        transfers affect the OE Companies' comparative earnings results with reductions
        in both revenues and expenses. Revenues are reduced due to the termination
        of
        certain arrangements with FES, under which the OE Companies previously sold
        their nuclear-generated KWH to FES and leased their non-nuclear generation
        assets to FGCO, a subsidiary of FES. Their expenses are lower due to the
        nuclear
        fuel and operating costs assumed by NGC as well as depreciation and property
        tax
        expenses assumed by FGCO and NGC related to the transferred generating assets.
        With respect to OE's retained leasehold interests in the Perry Plant and
        Beaver
        Valley Unit 2, OE has continued the nuclear-generated KWH sales arrangement
        with FES for the associated output and continues to be obligated on the
        applicable portion of expenses related to those interests. In addition, the
        OE
        Companies receive interest income on associated company notes receivable
        from
        the transfer of their generation net assets. FES will continue to provide
        OE’s
        PLR requirements under revised purchased power arrangements for the three-year
        period beginning January 1, 2006 and Penn’s during 2006 (see Outlook - Regulatory
        Matters).
 
 
 
  75
  The effects on the OE Companies' results of operations in the second quarter
        and
        first six months of 2006 as compared to the same periods of 2005 from the
        generation asset transfers (also reflecting OE's retained leasehold interests
        discussed above) are summarized in the following table:
  **Intra-System
                    Generation Asset Transfers****Income
                    Statement Effects**
                
                
                **Three
                    Months**
                
                **Six
                    Months****Increase
                    (Decrease)**
                
                
                ***(In
                    millions)***Revenues:Non-nuclear
                    generating units rent
                
                (a
                )
                $
                (44
                )
                $
                (89
                )Nuclear
                    generated KWH sales
                
                (b
                )
                
                (67
                )
                
                (131
                )Total
                    -
                    Revenues Effect
                
                
                
                
                (111
                )
                
                (220
                )Expenses:Fuel
                    costs -
                    nuclear
                
                (c
                )
                
                (9
                )
                
                (18
                )Nuclear
                    operating costs
                
                (c
                )
                
                (43
                )
                
                (89
                )Provision
                    for
                    depreciation
                
                (d
                )
                
                (17
                )
                
                (28
                )General
                    taxes
                
                (e
                )
                
                (3
                )
                
                (6
                )Total
                    -
                    Expenses Effect
                
                
                
                
                (72
                )
                
                (141
                )Operating
                    Income Effect
                
                
                
                
                (39
                )
                
                (79
                )Other
                    Income:Interest
                    income from notes receivable
                
                (f
                )
                
                14
                
                
                30Nuclear
                    decommissioning trust earnings
                
                (g
                )
                
                (4
                )
                
                (6
                )Capitalized
                    Interest
                
                (h
                )
                
                (2
                )
                
                (4
                )Total
                    - Other
                    Income Effect
                
                
                
                
                8.
                
                
                20.Income
                    taxes
                
                (i
                )
                
                (13
                )
                
                (24
                )Net
                    Income
                    Effect
                
                
                
                $
                (18
                )
                $
                (35
                )(a)
                    Elimination of non-nuclear generation assets lease to
                    FGCO.(b)
                    Reduction
                    of nuclear generated wholesale KWH sales to FES.(c)
                    Reduction
                    of nuclear fuel and operating costs.(d)
                    Reduction
                    of depreciation expense and asset retirement obligation accretion
                    related
                    to generation assets.(e)
                    Reduction
                    of property tax expense on generation assets.(f)
                    Interest
                    income on associated company notes receivable from the transfer
                    of
                    generation net assets.(g)
                    Reduction
                    of earnings on nuclear decommissioning trusts.(h)
                    Reduction
                    of allowance for borrowed funds used during construction on nuclear
                    capital expenditures.(i)
                    Income tax
                    effect of the above
                    adjustments.
  **Results
        of Operations**
 
 Earnings
        on common
        stock in the second quarter of 2006 increased to $56 million from
        $46 million in the second quarter of 2005. In the first six months of 2006,
        earnings on common stock increased to $119 million from $103 million in the
        same
        period of 2005. The increase in earnings in both periods of 2006 primarily
        resulted from lower expenses and increased other income, partially offset
        by
        lower revenues principally from the asset transfer effects shown in the table
        above. Earnings in both periods of 2005 were also reduced by a one-time income
        tax charge of $36 million from the enactment of tax legislation in Ohio.
        Earnings in the first six months of 2005 was additionally reduced by charges
        relating to a $8.5 million civil penalty payable to the Department of Justice
        and $10 million for environmental projects in connection with the Sammis
        Plant
        settlement (see Outlook — Environmental Matters).
 
 *Revenues*
 
 Revenues
        decreased
        by $144 million or 20.0% in the second quarter of 2006 compared with the
        same
        period in 2005, primarily due to the generation asset transfer impact summarized
        in the table above. Excluding the effects of the asset transfer, revenues
        in the
        second quarter of 2006 decreased $33 million, primarily due to decreases
        of
        $70 million and $112 million in wholesale sales and distribution
        revenues, respectively, partially offset by increases in retail generation
        revenues of $125 million and reduced customer shopping incentives of
        $21 million.
 
 In
        the first six
        months of 2006 compared with the same period in 2005, revenues decreased
        by $284
        million or 19.7%, primarily from the generation asset transfer impact summarized
        in the table above. Excluding the effects of the asset transfer, revenues
        in the
        first six months of 2006 decreased $64 million, primarily due to decreases
        of
        $130 million and $210 million in wholesale sales and distribution revenues,
        respectively, partially offset by increases in retail generation revenues
        of
        $232 million and reduced customer shopping incentives of $38
        million.
  76
  
 The
        lower wholesale
        revenues in both periods of 2006 reflect 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.
 
 Changes
        in electric
        generation KWH sales and revenues
        in the
        second quarter and first six months of 2006 from the corresponding periods
        of
        2005 are summarized in the following table.
 
 **Changes
                  in Generation KWH Sales**
              
              **Three
                  Months**
              
              **Six
                  Months****Increase
                  (Decrease)**Electric
                  Generation:Retail
              
              
              13.8
              %
              
              12.5
              %Wholesale
              
              
              (84.2)
              %
              
              (82.8)
              %**Net
                  Decrease in Generation Sales**
              
              
              **(31.4)**
              **%**
              
              **(29.7)**
              **%**
 
 **Changes
                      in Generation Revenues**
                  
                  **Three
                      Months**
                  
                  **Six
                      Months****Increase
                      (Decrease)**
                  
                  ***(In
                      millions)***Retail
                      Generation:Residential
                  
                  $
                  41
                  
                  $
                  84Commercial
                  
                  
                  38
                  
                  
                  70Industrial
                  
                  
                  46
                  
                  
                  78Total
                      Retail
                      Generation
                  
                  
                  125
                  
                  
                  232Wholesale*
                  
                  
                  (70
                  )
                  
                  (130
                  )**Net
                      Increase in Generation Revenues**
                  
                  **$**
                  **55**
                  
                  **$**
                  **102***
                      Excludes
                      impact of generation asset transfers related to nuclear generated
                      KWH
                      sales.
  Increased
        retail generation
        revenues for the second quarter of 2006 as shown in the table above resulted
        from higher KWH sales and higher unit prices. The increase in generation
        KWH
        sales primarily resulted from decreased customer shopping, as the percentage
        of
        generation services provided by alternative suppliers to total sales delivered
        in OE's service area decreased by: residential - 10.4 percentage points;
        commercial - 12.5 percentage points; and industrial - 11.2 percentage points.
        The decrease in shopping resulted from certain alternative energy suppliers
        terminating their supply arrangements with OE’s shopping customers in the fourth
        quarter of 2005. Higher unit prices for generation reflected the rate
        stabilization charge and the fuel recovery rider that both became effective
        in
        the first quarter of 2006 under provisions of the RSP and RCP.
 
 Retail
        generation
        revenues increased in the first six months of 2006 compared to the same period
        of 2005 for the reasons described above. The increase in generation KWH sales
        primarily resulted from a decrease in customer shopping, as the percentage
        of
        generation services provided by alternative suppliers to total sales delivered
        in OE's service area decreased by: residential - 9.5 percentage points;
        commercial - 11.8 percentage points; and industrial - 10.2 percentage points.
        Higher unit prices for generation reflected the impact of the RSP and RCP
        described above.
 
 Changes
        in
        distribution KWH deliveries and revenues in the
        second quarter and first six months of 2006 from the corresponding periods
        of
        2005 are summarized in the following table.
  **Changes
                    in Distribution KWH Deliveries**
                **Three
                    Months**
                
                **Six
                    Months****Increase
                    (Decrease)**Distribution
                    Deliveries:Residential
                (6.3)
                %
                
                (3.8)
                %Commercial
                (2.2)
                %
                
                (1.6)
                %Industrial
                2.7
                %
                
                0.5
                %**Net
                    Decrease in Distribution Deliveries**
                **(1.7)**
                **%**
                
                **(1.6)**
                **%**
  **Changes
                      in Distribution Revenues**
                  
                  **Three
                      Months**
                  
                  **Six
                      Months****Increase
                      (Decrease)**
                  
                  ***(In
                      millions)***Residential
                  
                  $
                  (48
                  )
                  $
                  (88
                  )Commercial
                  
                  
                  (34
                  )
                  
                  (65
                  )Industrial
                  
                  
                  (30
                  )
                  
                  (57
                  )**Net
                      Decrease in Distribution Revenues**
                  
                  **$**
                  **(112**
                  **)**
                  **$**
                  **(210**
                  **)**
  77
  
 Lower
        distribution
        throughput revenues as shown in the table above in the second quarter and
        first
        six months of 2006 reflects lower composite prices and reduced KWH deliveries.
        The lower unit prices in both periods were due to the completion of the
        generation-related transition cost recovery under the OE Companies’ respective
        rate restructuring plans in 2005, partially offset by increased transmission
        rates to recover MISO costs beginning in 2006 (see Outlook - Regulatory
        Matters). Lower distribution KWH deliveries to residential and commercial
        customers reflected the impact of milder weather conditions in the second
        quarter and first six months of 2006, compared to the same periods of 2005.
        KWH
        deliveries to industrial customers increased slightly in both periods due
        to the
        recovering steel industry in the OE Companies’ service territory.
 
 Under
        the Ohio
        transition plan, OE had provided incentives to customers to encourage switching
        to alternative energy providers, which reduced OE’s revenues by $21 million in
        the second quarter of 2005 and $38 million in the first six months of 2005.
        These revenue reductions, which were deferred for future recovery and did
        not
        affect earnings, ceased in 2006. The deferred shopping incentives (Extended
        RTC)
        are now being recovered under the RCP (see Outlook - Regulatory
        Matters).
 
 *Expenses*
 
 Total
        expenses
        decreased by $82 million in the second quarter of 2006 and $181 million in
        the
        first six months of 2006 from the same periods 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.
 
 
 **Expenses
                  - Changes**
              
              **Three
                  Months**
              
              **Six
                  Months****Increase
                  (Decrease)**
              
              ***(In
                  millions)***Purchased
                  power costs
              
              $
              66
              
              $
              102Nuclear
                  operating costs
              
              
              (6
              )
              
              (14
              )Other
                  operating costs
              
              
              (4
              )
              
              4Provision
                  for
                  depreciation
              
              
              2
              
              
              6Amortization
                  of regulatory assets
              
              
              (66
              )
              
              (124
              )Deferral
                  of
                  new regulatory assets
              
              
              (3
              )
              
              (15
              )General
                  taxes
              
              
              1
              
              
              2**Net
                  decrease in expenses**
              
              **$**
              **(10**
              **)**
              **$**
              **(39**
              **)**
 
 I ncreased
        purchased
        power costs in the second quarter and first six months of 2006 reflected
        higher
        unit prices associated with the new power supply agreement with FES, partially
        offset by a decrease in KWH purchased to meet the lower net generation sales
        requirements. Excluding the effects of the generation asset transfers, the
        lower
        nuclear operating costs for OE’s nuclear leasehold interests were primarily due
        to the absence in 2006 of the Beaver Valley Unit 2 refueling outage and Perry
        Nuclear Power Plant scheduled refueling outage (including an unplanned
        extension) that was completed on May 6, 2005. The decrease in other operating
        costs during the second quarter of 2006 was primarily due to lower associated
        company (FES) transmission expenses as a result of alternative energy suppliers
        terminating their supply arrangements with OE’s shopping customer in the fourth
        quarter of 2005. The increase in other operating costs in the first six months
        of 2006 was primarily due to increased transmission expenses related to MISO
        Day
        2 operations that began on April 1, 2005.
 
 Excluding
        the
        effects of the generation asset transfers, higher depreciation expense in
        the
        second quarter and first six months of 2006 reflected capital additions
        subsequent to the second quarter of 2005. Lower amortization of regulatory
        assets in both periods was due to the completion of the generation-related
        transition cost amortization under the OE Companies' respective transition
        plans, partially offset by the amortization of deferred MISO costs being
        recovered in 2006. The higher deferrals of new regulatory assets in the second
        quarter and first six months of 2006 primarily resulted from the deferral
        of
        fuel ($14 million and $25 million, respectively) and distribution costs
        ($22 million and $39 million, respectively) under the RCP, partially offset
        by lower MISO cost deferrals ($12 million and $11 million, respectively)
        and the
        decrease in shopping incentive deferrals ($21 million and $38 million,
        respectively) which ceased in 2006 under the Ohio transition plan. The deferral
        of interest on the unamortized shopping incentive balances continues under
        the
        RCP.
 
 Excluding
        the
        effects of the generation asset transfers, higher general taxes in both periods
        reflects the phase-in of the Ohio commercial activity tax that became effective
        July 1, 2005.
  78
  
 *Other
        Income*
 
 Other
        income
        increased $14 million in the second quarter of 2006 and $47 million in the
        first
        six months of 2006 as compared with the same periods of 2005, primarily due
        to
        the effects of the generation asset transfers. Excluding the effects of the
        generation asset transfers, the $5 million increase in the second quarter
        is
        primarily due to lower interest expense, reflecting debt redemptions subsequent
        to the second quarter of 2005.
 
 Excluding
        the
        effects of the generation asset transfers, the $28 million increase in the
        first
        six months is primarily due to lower interest expense and the absence in
        2006 of
        the 2005 charges of $8.5 million for a civil penalty payable to the DOJ and
        $10 million for environmental projects in connection with the Sammis New
        Source Review settlement (see Outlook - Environmental
        Matters).
 
 *Income
        Taxes*
 
 Income
        taxes
        decreased $60 million in the second quarter of 2006 and $75 million in the
        first
        six months of 2006 compared with the same periods of 2005. Excluding the
        effects
        of the generation asset transfer, income taxes decreased $47 million in the
        second quarter of 2006 and $50 million in the
        first six months of 2006. As a result of new
        Ohio tax legislation in 2005, OE wrote off $36 million in net deferred tax
        benefits in the second quarter of 2005. The remainder of the net change in
        both
        the second quarter and the six-month period was mainly 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.
 
 **Capital
        Resources and Liquidity**
 
 OE’s
        cash
        requirements in 2006 for operating expenses, construction expenditures and
        scheduled debt maturities are expected to be met with cash from operations,
        short-term credit arrangements and funds from capital markets. OE repurchased
        $500 million of common stock from FirstEnergy and redeemed $64 million of
        preferred stock in July 2006 with proceeds of senior notes issued in June
        2006.
        Available borrowing capacity under credit facilities will be used to manage
        working capital requirements.
 
 *Changes
        in Cash
        Position*
 
 OE
        had $545 million
        of cash and cash equivalents as of June 30, 2006 compared with $1 million
        as of
        December 31, 2005. The major sources for changes in these balances are
        summarized below.
 
 *Cash
        Flows From
        Operating Activities*
 
 Cash
        provided from
        operating activities during the first six months of 2006, compared with the
        corresponding period in 2005, was as follows:
 **Six
                    Months Ended****June
                    30,****Operating
                    Cash Flows**
                
                **2006**
                
                **2005****(*****In
                    millions)***Cash
                    earnings(1)
                
                $
                129
                
                $
                329Working
                    capital and other
                
                
                90
                
                
                135Net
                    cash
                    provided from operating activities
                
                $
                219
                
                $
                464
 (1)  Cash
          earnings are a
          non-GAAP measure (see reconciliation below).
 79
  
 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:
 
 **Six
                  Months Ended****June
                  30,****Reconciliation
                  of Cash Earnings**
              
              **2006**
              
              **2005****(*****In
                  millions)***Net
                  income
                  (GAAP)
              
              $
              123
              
              $
              104Non-cash
                  charges (credits):Provision
                  for
                  depreciation
              
              
              36
              
              
              58Amortization
                  of regulatory assets
              
              
              97
              
              
              221Deferral
                  of
                  new regulatory assets
              
              
              (78
              )
              
              (64
              )Nuclear
                  fuel
                  and capital lease amortization
              
              
              (11
              )
              
              19Amortization
                  of electric service obligation
              
              
              (17
              )
              
              (4
              )Amortization
                  of lease costs
              
              
              (4
              )
              
              (3
              )Deferred
                  income taxes and investment tax credits, net
              
              
              (17
              )
              
              (5
              )Accrued
                  compensation and retirement benefits
              
              
              --
              
              
              3Cash
                  earnings
                  (Non-GAAP)
              
              $
              129
              
              $
              329
 
 Net
        cash provided
        from operating activities decreased $245 million in the first six months
        of
        2006, compared with the same period in 2005, due to a $45 million decrease
        from
        changes in working capital and a $200 million decrease in cash earnings as
        described above under “Results from Operations.” The decrease in working capital
        primarily reflects the absence in 2006 of $136 million in funds received
        for the
        Energy for Education program in 2005, partially offset by changes in prepayments
        and other current assets of $78 million and accounts payable of
        $39 million.
 
 *Cash
        Flows From
        Financing Activities*
 
 Net
        cash provided
        from financing activities increased to $240 million in the first six months
        of
        2006 from $283 million used for financing activities in the first six
        months of 2005. The increase primarily reflected more long-term debt financing,
        and decreases of $151 million in redemptions of preferred stock and long-term
        debt and $142 million in common stock dividend payments to FirstEnergy,
        partially offset by higher repayments of short-term borrowings to associated
        companies.
 
 OE
        had approximately
        $1.1 billion of cash and temporary cash investments (which include
        short-term notes receivable from associated companies) and $25 million of
        short-term indebtedness as of June 30, 2006. OE has authorization from the
        PUCO to incur short-term debt of up to $500 million, which is available
        through the bank facility and the utility money pool described below. Penn
        has
        authorization from the 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
        $44 million as of June 30, 2006, and also has access to the bank
        facility and the utility money pool.
 
 OES
        Capital is a
        wholly owned subsidiary of OE whose borrowings are secured by customer accounts
        receivable purchased from OE. OES Capital can borrow up to $170 million
        under a receivables financing arrangement. As a separate legal entity with
        separate creditors, OES Capital would have to satisfy its obligations to
        creditors before any of its remaining assets could be made available to OE.
        As
        of June 30, 2006, the facility was not drawn.
 
 Penn
        Power Funding
        LLC (Penn Funding), a wholly owned subsidiary of Penn, is a limited liability
        company whose borrowings are secured by customer accounts receivable purchased
        from Penn. Penn Funding can borrow up to $25 million under a receivables
        financing arrangement which expires July 28,
        2007 .
        As a separate legal entity with separate creditors, Penn Funding would have
        to
        satisfy its obligations to creditors before any of its remaining assets could
        be
        made available to Penn. As
        of June 30,
        2006, the facility was drawn for $19 million.
 
 As
        of June 30, 2006,
        OE and Penn had the aggregate capability to issue approximately
        $592 million of additional FMB on the basis of property additions and
        retired bonds under the terms of their respective mortgage indentures. The
        issuance of FMB by OE is also subject to provisions of its senior note indenture
        generally limiting the incurrence of additional secured debt, subject to
        certain
        exceptions that would permit, among other things, the issuance of secured
        debt
        (including FMB) (i) supporting pollution control notes or similar obligations,
        or (ii) as an extension, renewal or replacement of previously outstanding
        secured debt. In addition, OE is permitted under the indenture to incur
        additional secured debt not otherwise permitted by a specified exception
        of up
        to $735 million as of June 30, 2006. Based upon applicable earnings
        coverage tests in their respective charters, OE and Penn could issue a total
        of
        $2.7 billion of preferred stock (assuming no additional debt was issued) as
        of June 30, 2006. As a result
        of OE
        redeeming all of its outstanding preferred stock on July 7, 2006, the applicable
        earnings coverage test is inoperable for OE. In the event that OE issues
        preferred stock in the future, the applicable earnings coverage test will
        govern
        the amount of additional preferred stock that OE may
        issue.
  80
  
 As
        of June 30, 2006,
        OE had approximately $400 million of capacity remaining unused under its
        existing shelf registration.
 
 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 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 $726 million as of June 30, 2006.
 
 The
        revolving credit
        facility contains financial covenants requiring each borrower to maintain
        a
        consolidated debt to total capitalization ratio of no more than 65%. As of
        June
        30, 2006, debt to total capitalization as defined under the revolving credit
        facility was 40% for OE and 34% for Penn.
 
 The
        facility does
        not contain any provisions that either restricts the ability of OE and Penn
        to
        borrow or accelerate repayment of outstanding advances as a result of any
        change
        in credit ratings. Pricing is defined in “pricing grids”, whereby the cost of
        funds borrowed under the facility is related to OE’s and Penn’s credit
        ratings.
 
 OE
        and Penn have the
        ability to borrow from their regulated affiliates and FirstEnergy to meet
        their
        short-term working capital requirements. FESC administers this money pool
        and
        tracks surplus funds of FirstEnergy and its regulated subsidiaries. Companies
        receiving a loan under the money pool agreements must repay the principal
        amount, together with accrued interest, within 364 days of borrowing the
        funds.
        The rate of interest is the same for each company receiving a loan from the
        pool
        and is based on the average cost of funds available through the pool. The
        average interest rate for borrowings in the first six months of 2006 was
        4.86%.
  OE’s
        access to the capital markets and the costs of financing are influenced by
        the
        ratings of its securities. The ratings outlook from S&P on all securities is
        stable. The ratings outlook from Moody's and Fitch on all securities is
        positive.
  On April 3, 2006, pollution control notes that were formerly obligations
        of OE
        and Penn were refinanced and became obligations of FGCO and NGC. The proceeds
        from the refinancings were used to repay a portion of 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 provided
        from investing activities was $86 million in the first six months of 2006
        compared to $181 million used for investing activities in the first six
        months of 2005. The change resulted primarily from a $171 million increase
        in
        loan repayments from associated companies and a $72 million decrease in
        property additions, which reflects the impact of the generation asset transfers.
 
 During
        the second
        half of 2006, capital requirements for property additions and capital leases
        are
        expected to be approximately $46 million. OE has additional requirements
        of
        approximately $2 million to meet requirements for maturing long-term debt
        during
        the remainder of 2006. These cash requirements are expected to be satisfied
        from
        a combination of internal cash and short-term credit arrangements. OE’s
        capital
        spending for the period 2006-2010 is expected to be approximately $ 624 million,
        of which
        approximately $ 108 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 $640 million as of June 30, 2006.
  81
  
 **Equity
        Price Risk**
 
 Included
        in OE’s
        nuclear decommissioning trust investments are marketable equity securities
        carried at their market value of approximately $70 million and $67 million
        as of
        June 30, 2006 and December 31, 2005, respectively. A hypothetical 10%
        decrease in prices quoted by stock exchanges would result in a $7 million
        reduction in fair value as of June 30, 2006. Changes in the fair value of
        these investments are recorded in OCI unless recognized as a result of a
        sale or
        recognized as regulatory assets or liabilities.
 
 **Outlook**
 
 The
        electric industry continues to transition to a more competitive environment
        and
        all of the OE Companies’ customers can select alternative energy suppliers. The
        OE Companies continue to deliver power to residential homes and businesses
        through their existing distribution system, which remains regulated. Customer
        rates have been restructured into separate components to support customer
        choice. In Ohio and Pennsylvania, the OE Companies have a continuing
        responsibility to provide power to those customers not choosing to receive
        power
        from an alternative energy supplier subject to certain limits.
 
 *Regulatory
        Matters*
 
 Regulatory assets and liabilities are costs which have been authorized by
        the
        PUCO, the PPUC and the FERC for recovery from or credit to customers in future
        periods or for which authorization is probable. Without the probability of
        such
        authorization, costs currently recorded as regulatory assets and liabilities
        would have been charged 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
        $756 million and $775 million as of June 30, 2006 and December
        31, 2005, respectively. Penn had net regulatory liabilities of $59 million
        as of June 30, 2006 and December 31, 2005, which are included in Other
        Noncurrent Liabilities on the Consolidated Balance Sheets as of June 30,
        2006
        and December 31, 2005.
 
 On
        October 21, 2003
        the Ohio Companies filed their RSP case with the PUCO. On August 5, 2004,
        the
        Ohio Companies accepted the RSP as modified and approved by the PUCO in an
        August 4, 2004 Entry on Rehearing, subject to a CBP. The RSP was intended
        to
        establish generation service rates beginning January 1, 2006, in response
        to the
        PUCO’s concerns about price and supply uncertainty following the end of the Ohio
        Companies' transition plan market development period. In October 2004, the
        OCC
        and NOAC filed appeals with the Supreme Court of Ohio to overturn the original
        June 9, 2004 PUCO order in the proceeding as well as the associated entries
        on
        rehearing. On September 28, 2005, the Supreme Court of Ohio heard oral arguments
        on the appeals. On May 3, 2006, the Supreme Court of Ohio issued an opinion
        affirming the PUCO's order with respect to the approval of the rate
        stabilization charge, approval of the shopping credits, the granting of interest
        on shopping credit incentive deferral amounts, and approval of the Ohio
        Companies’ financial separation plan. It remanded one matter back to the PUCO
        for further consideration of the issue as to whether the RSP, as adopted
        by the
        PUCO, provided for sufficient means for customer participation in the
        competitive marketplace. On May 12, 2006, the Ohio Companies filed a Motion
        for
        Reconsideration with the Supreme Court of Ohio which was denied by the Court
        on
        June 21, 2006. The RSP contained a provision that permitted the Ohio Companies
        to withdraw and terminate the RSP in the event that the PUCO, or the Supreme
        Court of Ohio, rejected all or part of the RSP. In such event, the Ohio
        Companies have 30 days from the final order or decision to provide notice
        of
        termination. On July 20, 2006 the Ohio Companies filed with the PUCO a Request
        to Initiate a Proceeding on Remand. In their Request, the Ohio Companies
        provided notice of termination to those provisions of the RSP subject to
        termination, subject to being withdrawn, and also set forth a framework for
        addressing the Supreme Court of Ohio’s findings on customer participation,
        requesting the PUCO to initiate a proceeding to consider the Ohio Companies’
proposal. If the PUCO approves a resolution to the issues raised by the Supreme
        Court of Ohio that is acceptable to the Ohio Companies, the Ohio Companies’
termination will be withdrawn and considered to be null and void. Separately,
        the OCC and NOAC also submitted to the PUCO on July 20, 2006 a conceptual
        proposal dealing with the issue raised by the Supreme Court of Ohio. On July
        26,
        2006, the PUCO issued an Entry acknowledging the July 20, 2006 filings of
        the
        Ohio Companies and the OCC and NOAC, and giving the Ohio Companies 45 days
        to
        file a plan in a new docket to address the Court’s concern.
  The Ohio Companies filed an application and stipulation with the PUCO on
        September 9, 2005 seeking approval of the RCP. On November 4, 2005, the Ohio
        Companies filed a supplemental stipulation with the PUCO, which constituted
        an
        additional component of the RCP filed on September 9, 2005. Major provisions
        of
        the RCP include:
 
 ●
              Maintaining
                  the existing level of base distribution rates through December 31,
                  2008 for OE;●
              Deferring
                  and
                  capitalizing for future recovery (over a 25-year period) with carrying
                  charges certain distribution costs to be incurred by all of the
                  Ohio
                  Companies during the period January 1, 2006 through December 31,
                  2008, not to exceed $150 million in each of the three
                  years;
   82
  ●
              Adjusting
                  the
                  RTC and extended RTC recovery periods and rate levels so that full
                  recovery of authorized costs will occur as of December 31, 2008 for
                  OE;●
              Reducing
                  the
                  deferred shopping incentive balances as of January 1, 2006 by up to
                  $75 million for OE by accelerating the application of its accumulated
                  cost of removal regulatory liability; and●
              Recovering
                  increased fuel costs (compared to a 2002 baseline) of up to $75
                  million,
                  $77 million, and $79 million, in 2006, 2007, and 2008,
                  respectively, from all OE and TE distribution and transmission
                  customers
                  through a fuel recovery mechanism. The Ohio Companies may defer
                  and
                  capitalize (for recovery over a 25-year period) increased fuel
                  costs above
                  the amount collected through the fuel recovery mechanism.
  The following table provides OE’s estimated net amortization of regulatory
        transition costs and deferred shopping incentives (including associated carrying
        charges) under the RCP for the period 2006 through 2008:
 **Amortization****Period**
                
                **Amortization*****(In
                    millions)***2006
                
                $
                1772007
                
                
                1802008
                
                
                208**Total
                    Amortization**
                
                **$**
                **565**
   On
        January 4, 2006, the
        PUCO approved, with modifications, the Ohio Companies’ RCP to supplement the RSP
        to provide customers with more certain rate levels than otherwise available
        under the RSP during the plan period. On January 10, 2006, the Ohio
        Companies filed a Motion for Clarification of the PUCO order approving the
        RCP.
        The Ohio Companies sought clarity on issues related to distribution deferrals,
        including requirements of the review process, timing for recognizing certain
        deferrals and definitions of the types of qualified expenditures. The Ohio
        Companies also sought confirmation that the list of deferrable distribution
        expenditures originally included in the revised stipulation fall within the
        PUCO
        order definition of qualified expenditures. On January 25, 2006, the PUCO
        issued an Entry on Rehearing granting in part, and denying in part, the Ohio
        Companies’ previous requests and clarifying issues referred to above. The PUCO
        granted the Ohio Companies’ requests to:
 
 ·
              Recognize
                  fuel
                  and distribution deferrals commencing January 1,
                  2006;·
              Recognize
                  distribution deferrals on a monthly basis prior to review by the
                  PUCO
                  Staff;·
              Clarify
                  that
                  the types of distribution expenditures included in the Supplemental
                  Stipulation may be deferred; and·
              Clarify
                  that
                  distribution expenditures do not have to be “accelerated” in order to be
                  deferred.
  The PUCO approved the Ohio Companies’ methodology for determining distribution
        deferral amounts, but denied the Motion in that the PUCO Staff must verify
        the
        level of distribution expenditures contained in current rates, as opposed
        to
        simply accepting the amounts contained in the Ohio Companies’ Motion. On
        February 3, 2006, several other parties filed applications for rehearing on
        the PUCO's January 4, 2006 Order. The Ohio Companies responded to the
        applications for rehearing on February 13, 2006. In an Entry on Rehearing
        issued by the PUCO on March 1, 2006, all motions for rehearing were denied.
        Certain of these parties have subsequently filed notices of appeal with the
        Supreme Court of Ohio alleging various errors made by the PUCO in its order
        approving the RCP. The Ohio Companies’ Motion to Intervene in the appeals was
        granted by the Supreme Court on June 8, 2006. The Appellants’ Merit Briefs were
        filed at the Supreme Court on July 5, 2006. The Appellees include the PUCO
        and
        the Ohio Companies. The Appellees’ Merit Briefs are due on August 4, 2006.
        Appellants’ Reply Briefs will then be due on August 24, 2006.
   On December 30, 2004, OE filed with the PUCO two
        applications related to the recovery of transmission and ancillary service
        related costs. The first application sought recovery of these costs beginning
        January 1, 2006. The Ohio Companies requested that these costs be recovered
        through a rider that would be effective on January 1, 2006 and adjusted
        each July 1 thereafter. The parties reached a settlement agreement that was
        approved by the PUCO on August 31, 2005. The incremental transmission and
        ancillary service revenues recovered from January 1 through June 30, 2006
        were approximately $31 million. That amount included the recovery of a
        portion of the 2005 deferred MISO expenses as described below. On May 1,
        2006, OE filed a modification to the rider to determine revenues ($71 million)
        from July 2006 through June 2007.
  83
  The second application sought authority to defer costs associated with
        transmission and ancillary service related costs incurred during the period
        October 1, 2003 through December 31, 2005. On May 18, 2005, the
        PUCO granted the accounting authority for the Ohio Companies to defer
        incremental transmission and ancillary service-related charges incurred as
        a
        participant in MISO, but only for those costs incurred during the period
        December 30, 2004 through December 31, 2005. Permission to defer costs
        incurred prior to December 30, 2004 was denied. The PUCO also authorized
        the Ohio Companies to accrue carrying charges on the deferred balances. On
        August 31, 2005, the OCC appealed the PUCO's decision. On January 20,
        2006, the OCC sought rehearing of the PUCO’s approval of the recovery of
        deferred costs through the rider during the period January 1, 2006 through
        June 30, 2006. The PUCO denied the OCC's application on February 6,
        2006. On March 23, 2006, the OCC appealed the PUCO's order to the Ohio
        Supreme Court. On March 27, 2006, the OCC filed a motion to consolidate
        this appeal with the deferral appeals discussed above and to postpone oral
        arguments in the deferral appeal until after all briefs are filed in this
        most
        recent appeal of the rider recovery mechanism. On March 20, 2006, the Ohio
        Supreme Court, on its own motion, consolidated the OCC's appeal of the Ohio
        Companies' case with a similar case involving Dayton Power & Light Company.
        Oral arguments were heard on May 10, 2006. The Ohio Companies are unable to
        predict when a decision may be issued.
  Under Pennsylvania's electric competition law, Penn is required to secure
        generation supply for customers who do not choose alternative suppliers for
        their electricity. On October 11, 2005, Penn filed a plan with the PPUC to
        secure electricity supply for its customers at set rates following the end
        of
        its transition period on December 31, 2006. Penn recommended that the RFP
        process cover the period January 1, 2007 through May 31, 2008. To the
        extent that an affiliate of Penn supplies a portion of the PLR load included
        in
        the RFP, authorization to make the affiliate sale must be obtained from the
        FERC. Hearings before the PPUC were held on January 10, 2006 with main
        briefs filed on January 27, 2006 and reply briefs filed on February 3,
        2006. On February 16, 2006, the ALJ issued a Recommended Decision to adopt
        Penn's RFP process with modifications. On April 20, 2006, the PPUC approved
        the
        Recommended Decision with additional modifications to use an RFP process
        to
        obtain Penn's power supply requirements after 2006 through two separate
        solicitations. An initial solicitation was held for Penn in May 2006 with
        all
        tranches fully subscribed. On June 2, 2006, the PPUC approved the bid results
        for the first solicitation. On July 18, 2006, the second PLR solicitation
        was
        held for Penn. The tranches for the Residential Group and Small Commercial
        Group
        were fully subscribed. However, supply was only acquired for three of the
        five
        tranches for the Large Commercial Group. On July 20, 2006, the PPUC approved
        the
        submissions for the second bid. A residual solicitation is scheduled to be
        held
        on August 15, 2006 for the two remaining Large Commercial Group tranches.
        Acceptance of the winning bids is subject to approval by the PPUC.
  On May 25, 2006, Penn filed a Petition for Review of the PPUC’s Orders of
        April 28, 2006 and May 4, 2006, which together decided the issues
        associated with Penn’s proposed Interim PLR Supply Plan. Penn has asked the
        Commonwealth Court to review the PPUC’s decision to deny its recovery of certain
        PLR costs via a reconciliation mechanism and its decision to impose a geographic
        limitation on the sources of alternative energy credits. On June 7, 2006,
        the PaDEP filed a Petition for Review appealing the PPUC’s ruling on the method
        by which alternative energy credits may be acquired and traded. Penn is unable
        to predict the outcome of this appeal.
 On November 1, 2005, FES filed two power sales agreements for approval with
        the FERC. One power sales agreement provided for FES to provide the PLR
        requirements of the Ohio Companies at a price equal to the retail generation
        rates approved by the PUCO for a period of three years beginning January 1,
        2006. The Ohio Companies will be relieved of their obligation to obtain PLR
        power requirements from FES if the Ohio CBP results in a lower price for
        retail
        customers. A similar power sales agreement between FES and Penn permits Penn
        to
        obtain its PLR power requirements from FES at a fixed price equal to the
        retail
        generation price during 2006. 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 through two separate solicitations. An initial solicitation was
        held
        for Penn in May 2006 with all tranches fully subscribed. On June 2, 2006,
        the
        PPUC approved the bid results for the first solicitation. On July 18, 2006,
        the
        second PLR solicitation was held for Penn. The tranches for the Residential
        Group and Small Commercial Group were fully subscribed. However, supply was
        only
        acquired for three of the five tranches for the Large Commercial Group. On
        July
        20, 2006, the PPUC approved the submission for the second bid. A residual
        solicitation is scheduled to be held on August 15, 2006 for the two remaining
        Large Commercial Group tranches. Acceptance of the winning bids is subject
        to
        approval by the PPUC.
 
 On December 29, 2005, the FERC issued an order setting the two power sales
        agreements for hearing. The order criticized the Ohio CBP, and required FES
        to
        submit additional evidence in support of the reasonableness of the prices
        charged in the power sales agreements. A pre-hearing conference was held
        on
        January 18, 2006 to determine the hearing schedule in this case. Under
        the procedural schedule, approved in this case, FES expected an initial decision
        to be issued in late January 2007. However, on July 14, 2006, the
        Chief Judge granted the joint motion of FES and the Trial Staff to appoint
        a
        settlement judge in this proceeding. The procedural schedule has been suspended
        pending negotiations among the parties.
  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.
  84
  *Environmental
        Matters*
  OE accrues environmental liabilities only when it concludes that it is probable
        that it has an obligation for such costs and can reasonably estimate the
        amount
        of such costs. Unasserted claims are reflected in OE’s determination of
        environmental liabilities and are accrued in the period that they are both
        probable and reasonably estimable.
  *W. H. Sammis Plant-*
  In 1999 and 2000, the EPA issued NOV or Compliance Orders to nine utilities
        alleging violations of the Clean Air Act based on operation and maintenance
        of
        44 power plants, including the W. H. Sammis Plant, which was owned at that
        time
        by OE and Penn. In addition, the DOJ filed eight civil complaints against
        various investor-owned utilities, including a complaint against OE and Penn
        in
        the U.S. District Court for the Southern District of Ohio. These cases are
        referred to as New Source Review cases. On March 18, 2005, OE and Penn
        announced that they had reached a settlement with the EPA, the DOJ and three
        states (Connecticut, New Jersey, and New York) that resolved all issues related
        to the W. H. Sammis Plant New Source Review litigation. This settlement
        agreement was approved by the Court on July 11, 2005, and requires
        reductions of NO X and SO 2 emissions at the W.
        H. Sammis Plant and other coal fired plants through the installation of
        pollution control devices and provides for stipulated penalties for failure
        to
        install and operate such pollution controls in accordance with that agreement.
        Those requirements will be the responsibility of FGCO. The settlement agreement
        also requires OE and Penn to spend up to $25 million toward environmentally
        beneficial projects, which include wind energy purchased power agreements
        over a
        20-year term. OE and Penn agreed to pay a civil penalty of $8.5 million.
        Results for the first quarter of 2005 included the penalties paid by OE and
        Penn
        of $7.8 million and $0.7 million, respectively. OE and Penn also
        recognized liabilities in the first quarter of 2005 of $9.2 million and
        $0.8 million, respectively, for probable future cash contributions toward
        environmentally beneficial projects.
 
 See
        Note 10(B)
        to the consolidated financial statements for further details and a complete
        discussion of environmental matters.
 
 *Other
        Legal
        Proceedings*
 
 There
        are various
        lawsuits, claims (including claims for asbestos exposure) and proceedings
        related to OE’s normal business operations pending against OE and its
        subsidiaries. The other potentially material items not otherwise discussed
        above
        are described below.
  *Power
        Outages and Related Litigation-*
  On August 14, 2003, various states and parts of southern Canada experienced
        widespread power outages. The outages affected approximately 1.4 million
        customers in FirstEnergy's service area. The U.S. - Canada Power System Outage
        Task Force’s final report in April 2004 on the outages concluded, among other
        things, that the problems leading to the outages began in FirstEnergy’s Ohio
        service area. Specifically,
        the
        final report concluded, among other things, that the initiation of the
        August 14, 2003 power outages resulted from an alleged failure of both
        FirstEnergy and ECAR to assess and understand perceived inadequacies within
        the
        FirstEnergy system; inadequate situational awareness of the developing
        conditions; and a perceived failure to adequately manage tree growth in certain
        transmission rights of way. The Task Force also concluded that there was
        a
        failure of the interconnected grid's reliability organizations (MISO and
        PJM) to
        provide effective real-time diagnostic support. The final report is publicly
        available through the Department of Energy’s Web site (www.doe.gov). FirstEnergy
        believes that the final report does not provide a complete and comprehensive
        picture of the conditions that contributed to the August 14, 2003 power
        outages and that it does not adequately address the underlying causes of
        the
        outages. FirstEnergy remains convinced that the outages cannot be explained
        by
        events on any one utility's system. The final report contained 46
“recommendations to prevent or minimize the scope of future blackouts.”
Forty-five of those recommendations related to broad industry or policy matters
        while one, including subparts, related to activities the Task Force recommended
        be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct
        the
        causes of the August 14, 2003 power outages. FirstEnergy implemented
        several initiatives, both prior to and since the August 14, 2003 power
        outages, which were independently verified by NERC as complete in 2004 and
        were
        consistent with these and other recommendations and collectively enhance
        the
        reliability of its electric system. FirstEnergy’s implementation of these
        recommendations in 2004 included completion of the Task Force recommendations
        that were directed toward FirstEnergy. FirstEnergy is also proceeding with
        the
        implementation of the recommendations that were to be completed subsequent
        to
        2004 and will continue to periodically assess the FERC-ordered Reliability
        Study
        recommendations for forecasted 2009 system conditions, recognizing revised
        load
        forecasts and other changing system conditions which may impact the
        recommendations. Thus far, implementation of the recommendations has not
        required, nor is expected to require, substantial investment in new or material
        upgrades to existing equipment. The FERC or other applicable government agencies
        and reliability coordinators may, however, take a different view as to
        recommended enhancements or may recommend additional enhancements in the
        future
        as the result of adoption of mandatory reliability standards pursuant to
        the
        EPACT that could require additional material expenditures.
  85
  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. Three other pending PUCO complaint cases, were filed by various
        insurance carriers either in their own name as subrogees or in the name of
        their
        insured. In each of these three cases, the carrier seeks reimbursement from
        various FirstEnergy companies (and, in one case, from PJM, MISO and American
        Electric Power Company, Inc., as well) for claims paid to insureds for
        damages allegedly arising as a result of the loss of power on August 14,
        2003. The listed insureds in these cases, in many instances, are not customers
        of any FirstEnergy company. The sixth case involves the claim of a non-customer
        seeking reimbursement for losses incurred when its store was burglarized
        on
        August 14, 2003. FirstEnergy filed a Motion to Dismiss on June 13, 2006. It
        is currently expected that this case will be summarily dismissed, although
        the
        Motion is still pending. 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 as a defendant; ruled that
        the
        U.S.-Canada Power System Outage Task Force Report was not admissible into
        evidence; and gave the plaintiffs additional time to amend their complaints
        to
        otherwise comply with the PUCO’s underlying order. Also, most
        complainants, along with the FirstEnergy companies, filed applications for
        rehearing with the PUCO over various rulings contained in the March 7, 2006
        order. On April 26, 2006, the PUCO granted rehearing to allow the insurance
        company claimants, as insurers, to prosecute their claims in their name so
        long
        as they also identify the underlying insured entities and the Ohio utilities
        that provide their service. The PUCO denied all other motions for rehearing.
        The
        plaintiffs in each case have since filed an amended complaint and the named
        FirstEnergy companies have answered and also have filed a motion to dismiss
        each
        action. These motions are pending. Additionally, on June 23, 2006, one of
        the
        insurance carrier complainants filed an appeal with the Ohio Supreme Court
        over
        the PUCO’s denial of their motion for rehearing on the issue of the
        admissibility of the Task Force Report and the dismissal of FirstEnergy Corp.
        as
        a respondent. Briefing is expected to be completed on this appeal by
        mid-September. It is unknown when the Supreme Court will rule on the appeal.
        No
        estimate of potential liability is available for any of these cases.
  FirstEnergy
        is vigorously defending these actions, but cannot predict the outcome of
        any of
        these proceedings or whether any further regulatory proceedings or legal
        actions
        may be initiated against the Companies. Although unable to predict the impact
        of
        these proceedings, if FirstEnergy or its subsidiaries were ultimately determined
        to have legal liability in connection with these proceedings, it could have
        a
        material adverse effect on FirstEnergy's or its subsidiaries' financial
        condition, results of operations and cash flows.
 
 *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.
  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.
  86
  *Other
        Legal Matters-*
  On October 20, 2004, FirstEnergy was notified by the SEC that the
        previously disclosed informal inquiry initiated by the SEC's Division of
        Enforcement in September 2003 relating to the restatements in August 2003
        of
        previously reported results by FirstEnergy and the Ohio Companies, and the
        Davis-Besse extended outage, have become the subject of a formal order of
        investigation. The SEC's formal order of investigation also encompasses issues
        raised during the SEC's examination of FirstEnergy and the Companies under
        the
        now repealed PUHCA. Concurrent with this notification, FirstEnergy received
        a
        subpoena asking for background documents and documents related to the
        restatements and Davis-Besse issues. On December 30, 2004, FirstEnergy
        received a subpoena asking for documents relating to issues raised during
        the
        SEC's PUHCA examination. On August 24, 2005, additional information was
        requested regarding Davis-Besse related disclosures, which FirstEnergy has
        provided. FirstEnergy has cooperated fully with the informal inquiry and
        will
        continue to do so with the formal investigation.
 On August 22, 2005, a class action complaint was filed against OE in
        Jefferson County, Ohio Common Pleas Court, seeking compensatory and punitive
        damages to be determined at trial based on claims of negligence and eight
        other
        tort counts alleging damages from W.H. Sammis Plant air emissions. The two
        named
        plaintiffs are also seeking injunctive relief to eliminate harmful emissions
        and
        repair property damage and the institution of a medical monitoring program
        for
        class members.
  The
        City of Huron filed a complaint against OE with the PUCO challenging the
        ability
        of electric distribution utilities to collect transition charges from a customer
        of a newly-formed municipal electric utility. The complaint was filed on
        May 28, 2003, and OE timely filed its response on June 30, 2003. In a
        related filing, the Ohio Companies filed for approval with the PUCO of a
        tariff
        that would specifically allow the collection of transition charges from
        customers of municipal electric utilities formed after 1998. Both filings
        were
        consolidated for hearing and decision described above. An adverse ruling
        could
        negatively affect full recovery of transition charges by the utility. Hearings
        on the matter were held in August 2005. Initial briefs from all parties were
        filed on September 22, 2005 and reply briefs were filed on October 14,
        2005. On May 10, 2006, the PUCO issued its Opinion and Order dismissing the
        City’s complaint and approving the related tariffs, thus affirming OE’s
        entitlement to recovery of its transition charges. The City of Huron filed
        an
        application for rehearing of the PUCO’s decision on June 9, 2006 and OE
        filed a memorandum in opposition to that application on June 19, 2006. The
        PUCO denied the City’s application for rehearing on June 28, 2006. The City of
        Huron has 60 days from the denial of rehearing to appeal the PUCO’s
        decision.
  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**
 
 *FIN
        48 -
“Accounting for Uncertainty in Income Taxes - an interpretation of FASB
        Statement No. 109.”*
 
 In
        June 2006, the
        FASB issued FIN 48 which clarifies the accounting for uncertainty in income
        taxes recognized in an enterprise’s financial statements in accordance with FASB
        Statement No. 109, “Accounting for Income Taxes.” This interpretation prescribes
        a recognition threshold and measurement attribute for the financial statement
        recognition and measurement of a tax position taken or expected to be taken
        on a
        tax return. This interpretation also provides guidance on derecognition,
        classification, interest, penalties, accounting in interim periods, disclosure
        and transition. The evaluation of a tax position in accordance with this
        interpretation will be a two-step process. The first step will determine
        if it
        is more likely than not that a tax position will be sustained upon examination
        and should therefore be recognized. The second step will measure a tax position
        that meets the more likely than not recognition threshold to determine the
        amount of benefit to recognize in the financial statements. This interpretation
        is effective for fiscal years beginning after December 15, 2006. OE is currently
        evaluating the impact of this Statement.
  87
 **THE
                    CLEVELAND ELECTRIC ILLUMINATING COMPANY****CONSOLIDATED
                    STATEMENTS OF INCOME AND COMPREHENSIVE INCOME****(Unaudited)****Three
                    Months Ended**
                  **June
                    30,**
                
                
                **Six
                    Months
                    Ended**
                  **June
                    30,****2006**
                
                
                **2005**
                
                
                **2006**
                
                
                **2005***(In
                    thousands)***STATEMENTS
                    OF INCOME****REVENUES**
                
                $
                432,371
                
                $
                448,747
                
                $
                840,181
                
                $
                881,920**EXPENSES:**Fuel
                
                
                13,413
                
                
                21,110
                
                
                26,976
                
                
                39,437Purchased
                    power
                
                
                157,942
                
                
                138,842
                
                
                301,711
                
                
                281,726Nuclear
                    operating costs
                
                
                -
                
                
                36,786
                
                
                -
                
                
                95,513Other
                    operating costs
                
                
                68,436
                
                
                74,711
                
                
                141,331
                
                
                138,284Provision
                    for
                    depreciation
                
                
                11,050
                
                
                33,387
                
                
                28,251
                
                
                64,502Amortization
                    of regulatory assets
                
                
                29,476
                
                
                55,016
                
                
                61,006
                
                
                109,042Deferral
                    of
                    new regulatory assets
                
                
                (31,698
                )
                
                (40,701
                )
                
                (62,223
                )
                
                (65,989
                )General
                    taxes
                
                
                31,510
                
                
                36,605
                
                
                66,580
                
                
                75,492Total
                    expenses
                
                
                280,129
                
                
                355,756
                
                
                563,632
                
                
                738,007**OPERATING
                    INCOME**
                
                
                152,242
                
                
                92,991
                
                
                276,549
                
                
                143,913**OTHER
                    INCOME (EXPENSE):**Investment
                    income
                
                
                24,674
                
                
                14,049
                
                
                51,610
                
                
                29,197Miscellaneous
                    income (expense)
                
                
                5,642
                
                
                (2,292
                )
                
                5,396
                
                
                (8,764
                )Interest
                    expense
                
                
                (34,634
                )
                
                (30,152
                )
                
                (69,366
                )
                
                (64,618
                )Capitalized
                    interest
                
                
                837
                
                
                1,294
                
                
                1,510
                
                
                883Total
                    other
                    income (expense)
                
                
                (3,481
                )
                
                (17,101
                )
                
                (10,850
                )
                
                (43,302
                )**INCOME
                    TAXES**
                
                
                57,709
                
                
                37,221
                
                
                102,234
                
                
                46,470**NET
                    INCOME**
                
                
                91,052
                
                
                38,669
                
                
                163,465
                
                
                54,141**PREFERRED
                    STOCK DIVIDEND REQUIREMENTS**
                
                
                -
                
                
                -
                
                
                -
                
                
                2,918**EARNINGS
                    ON COMMON STOCK**
                
                $
                91,052
                
                $
                38,669
                
                $
                163,465
                
                $
                51,223**STATEMENTS
                    OF COMPREHENSIVE INCOME****NET
                    INCOME**
                
                $
                91,052
                
                $
                38,669
                
                $
                163,465
                
                $
                54,141**OTHER
                    COMPREHENSIVE INCOME (LOSS):**Unrealized
                    loss on available for sale securities
                
                
                -
                
                
                (1,349
                )
                
                -
                
                
                (2,570
                )Income
                    tax
                    benefit related to other comprehensive income
                
                
                -
                
                
                419
                
                
                -
                
                
                923Other
                    comprehensive loss, net of tax
                
                
                -
                
                
                (930
                )
                
                -
                
                
                (1,647
                )**TOTAL
                    COMPREHENSIVE INCOME**
                
                $
                91,052
                
                $
                37,739
                
                $
                163,465
                
                $
                52,494The
                    preceding
                    Notes to Consolidated Financial Statements as they relate to
                    The Cleveland
                    Electric Illuminating Company
                  are
                    an
                    integral part of these statements.
   88
  **THE
                      CLEVELAND ELECTRIC ILLUMINATING COMPANY****CONSOLIDATED
                      BALANCE SHEETS****(Unaudited)****June
                      30,**
                  
                  
                  **December
                      31,****2006**
                  
                  
                  **2005*****(In
                      thousands)*****ASSETS****CURRENT
                      ASSETS:**Cash
                      and cash
                      equivalents
                  
                  $
                  217
                  
                  $
                  207Receivables-Customers
                      (less accumulated provisions of $5,836,000 and $5,180,000,respectively,
                      for uncollectible accounts)
                  
                  
                  273,324
                  
                  
                  268,427Associated
                      companies
                  
                  
                  37,168
                  
                  
                  86,564Other
                  
                  
                  14,703
                  
                  
                  16,466Notes
                      receivable from associated companies
                  
                  
                  29,048
                  
                  
                  19,378Prepayments
                      and other
                  
                  
                  1,504
                  
                  
                  1,903355,964
                  
                  
                  392,945**UTILITY
                      PLANT:**In
                      service
                  
                  
                  2,063,137
                  
                  
                  2,030,935Less
                      -
                      Accumulated provision for depreciation
                  
                  
                  800,356
                  
                  
                  788,9671,262,781
                  
                  
                  1,241,968Construction
                      work in progress
                  
                  
                  73,869
                  
                  
                  51,1291,336,650
                  
                  
                  1,293,097**OTHER
                      PROPERTY AND INVESTMENTS:**Long-term
                      notes receivable from associated companies
                  
                  
                  940,786
                  
                  
                  1,057,337Investment
                      in
                      lessor notes
                  
                  
                  519,615
                  
                  
                  564,166Other
                  
                  
                  13,710
                  
                  
                  12,8401,474,111
                  
                  
                  1,634,343**DEFERRED
                      CHARGES AND OTHER ASSETS:**Goodwill
                  
                  
                  1,688,521
                  
                  
                  1,688,966Regulatory
                      assets
                  
                  
                  858,618
                  
                  
                  862,193Prepaid
                      pension costs
                  
                  
                  137,082
                  
                  
                  139,012Property
                      taxes
                  
                  
                  63,500
                  
                  
                  63,500Other
                  
                  
                  33,130
                  
                  
                  27,6142,780,851
                  
                  
                  2,781,285$
                  5,947,576
                  
                  $
                  6,101,670**LIABILITIES
                      AND CAPITALIZATION****CURRENT
                      LIABILITIES:**Currently
                      payable long-term debt
                  
                  $
                  543
                  
                  $
                  75,718Short-term
                      borrowings-Associated
                      companies
                  
                  
                  154,731
                  
                  
                  212,256Other
                  
                  
                  149,000
                  
                  
                  140,000Accounts
                      payable-Associated
                      companies
                  
                  
                  65,148
                  
                  
                  74,993Other
                  
                  
                  8,121
                  
                  
                  4,664Accrued
                      taxes
                  
                  
                  119,555
                  
                  
                  121,487Accrued
                      interest
                  
                  
                  18,810
                  
                  
                  18,886Lease
                      market
                      valuation liability
                  
                  
                  60,200
                  
                  
                  60,200Other
                  
                  
                  39,512
                  
                  
                  61,308615,620
                  
                  
                  769,512**CAPITALIZATION:**Common
                      stockholder's equity-Common
                      stock,
                      without par value, authorized 105,000,000 shares -79,590,689
                      shares outstanding
                  
                  
                  1,355,926
                  
                  
                  1,354,924Retained
                      earnings
                  
                  
                  687,615
                  
                  
                  587,150Total
                      common
                      stockholder's equity
                  
                  
                  2,043,541
                  
                  
                  1,942,074Long-term
                      debt
                      and other long-term obligations
                  
                  
                  1,886,636
                  
                  
                  1,939,3003,930,177
                  
                  
                  3,881,374**NONCURRENT
                      LIABILITIES:**Accumulated
                      deferred income taxes
                  
                  
                  551,553
                  
                  
                  554,828Accumulated
                      deferred investment tax credits
                  
                  
                  22,093
                  
                  
                  23,908Lease
                      market
                      valuation liability
                  
                  
                  577,900
                  
                  
                  608,000Retirement
                      benefits
                  
                  
                  83,604
                  
                  
                  83,414Deferred
                      revenues - electric service programs
                  
                  
                  63,566
                  
                  
                  71,261Other
                  
                  
                  103,063
                  
                  
                  109,3731,401,779
                  
                  
                  1,450,784**COMMITMENTS
                      AND CONTINGENCIES (Note 10)**$
                  5,947,576
                  
                  $
                  6,101,670The
                      preceding
                      Notes to Consolidated Financial Statements as they relate to
                      The Cleveland
                      Electric Illuminating Company are an integral part of these
                      balance
                      sheets.
   89
  **THE
                            CLEVELAND ELECTRIC ILLUMINATING
                            COMPANY****CONSOLIDATED
                            STATEMENTS OF CASH FLOWS****(Unaudited)****Six
                            Months Ended****June
                            30,****2006**
                        
                        
                        **2005*****(In
                            thousands)*****CASH
                            FLOWS FROM OPERATING ACTIVITIES:**Net
                            income
                        $
                        163,465
                        
                        $
                        54,141Adjustments
                            to
                            reconcile net income to net cash from operating activities
                            -Provision
                            for
                            depreciation
                        
                        28,251
                        
                        
                        64,502Amortization
                            of regulatory assets
                        
                        61,006
                        
                        
                        109,042Deferral
                            of
                            new regulatory assets
                        
                        (62,223
                        )
                        
                        (65,989
                        )Nuclear
                            fuel
                            and capital lease amortization
                        
                        120
                        
                        
                        10,781Deferred
                            rents
                            and lease market valuation liability
                        
                        (55,043
                        )
                        
                        (53,691
                        )Deferred
                            income taxes and investment tax credits, net
                        
                        (4,745
                        )
                        
                        4,450Accrued
                            compensation and retirement benefits
                        
                        1,584
                        
                        
                        (373
                        )Decrease
                            (increase) in operating assets-Receivables
                        
                        46,262
                        
                        
                        (98,074
                        )Materials
                            and
                            supplies
                        
                        -
                        
                        
                        (28,791
                        )Prepayments
                            and other current assets
                        
                        399
                        
                        
                        188Increase
                            (decrease) in operating liabilities-Accounts
                            payable
                        
                        (6,388
                        )
                        
                        38,280Accrued
                            taxes
                        
                        (1,932
                        )
                        
                        (6,779
                        )Accrued
                            interest
                        
                        (76
                        )
                        
                        (320
                        )Electric
                            service prepayment programs
                        
                        (7,695
                        )
                        
                        57,466Other
                        
                        (4,162
                        )
                        
                        (7,871
                        )Net
                            cash
                            provided from operating activities
                        
                        158,823
                        
                        
                        76,962**CASH
                            FLOWS FROM FINANCING ACTIVITIES:**New
                            Financing-Long-term
                            debt
                        
                        -
                        
                        
                        53,284Short-term
                            borrowings, net
                        
                        -
                        
                        
                        58,874Equity
                            contributions from parent
                        
                        -
                        
                        
                        75,000Redemptions
                            and Repayments-Preferred
                            stock
                        
                        -
                        
                        
                        (101,900
                        )Long-term
                            debt
                        
                        (118,152
                        )
                        
                        (56,930
                        )Short-term
                            borrowings, net
                        
                        (57,675
                        )
                        
                        -Dividend
                            Payments-Common
                            stock
                        
                        (63,000
                        )
                        
                        (124,000
                        )Preferred
                            stock
                        
                        -
                        
                        
                        (2,260
                        )Net
                            cash used
                            for financing activities
                        
                        (238,827
                        )
                        
                        (97,932
                        )**CASH
                            FLOWS FROM INVESTING ACTIVITIES:**Property
                            additions
                        
                        (65,551
                        )
                        
                        (60,244
                        )Loan
                            repayments from associated companies, net
                        
                        108,169
                        
                        
                        66,927Investments
                            in
                            lessor notes
                        
                        44,551
                        
                        
                        32,473Proceeds
                            from
                            nuclear decommissioning trust fund sales
                        
                        -
                        
                        
                        198,974Investments
                            in
                            nuclear decommissioning trust funds
                        
                        -
                        
                        
                        (213,486
                        )Other
                        
                        (7,155
                        )
                        
                        (3,664
                        )Net
                            cash
                            provided from investing activities
                        
                        80,014
                        
                        
                        20,980Net
                            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 Company are an integral part of
                            these
                            statements.
 90
  
 
 ***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 June 30, 2006, and the related consolidated
        statements of income and comprehensive income for each of the three-month
        and
        six-month periods ended June 30, 2006 and 2005 and the consolidated statement
        of
        cash flows for the six-month period ended June 30, 2006 and 2005. These interim
        financial statements are the responsibility of the Company’s
        management.
 
 We
        conducted our
        review in accordance with the standards of the Public Company Accounting
        Oversight Board (United States). A review of interim financial information
        consists principally of applying analytical procedures and making inquiries
        of
        persons responsible for financial and accounting matters. It is substantially
        less in scope than an audit conducted in accordance with the standards of
        the
        Public Company Accounting Oversight Board, the objective of which is the
        expression of an opinion regarding the financial statements taken as a whole.
        Accordingly, we do not express such an opinion.
 
 Based
        on our review,
        we are not aware of any material modifications that should be made to the
        accompanying consolidated interim financial statements for them to be in
        conformity with accounting principles generally accepted in the United States
        of
        America.
 
 We
        have previously
        audited, in accordance with the standards of the Public Company Accounting
        Oversight Board (United States), the consolidated balance sheet as of December
        31, 2005, and the related consolidated statements of income, capitalization,
        common stockholder’s equity, preferred stock, cash flows and taxes for the year
        then ended (not presented herein), and in our report [which contained references
        to the Company’s change in its method of accounting for asset retirement
        obligations as of January 1, 2003 and conditional asset retirement obligations
        as of December 31, 2005 as discussed in Note 2(G) and Note 11 to those
        consolidated financial statements and the Company’s change in its method of
        accounting for the consolidation of variable interest entities as of December
        31, 2003 as discussed in Note 6 to those consolidated financial statements]
        dated February 27, 2006, we expressed an unqualified opinion on those
        consolidated financial statements. In our opinion, the information set forth
        in
        the accompanying consolidated balance sheet as of December 31, 2005, is fairly
        stated in all material respects in relation to the consolidated balance sheet
        from which it has been derived.
 
 
 
 
 PricewaterhouseCoopers
        LLP
 Cleveland,
        Ohio
 August
        4,
        2006
 
 
  91
  **THE
        CLEVELAND ELECTRIC ILLUMINATING COMPANY**
 
 **MANAGEMENT’S
        DISCUSSION AND ANALYSIS OF**
 **RESULTS
        OF
        OPERATIONS AND FINANCIAL CONDITION**
 
 
 CEI
        is a wholly
        owned, electric utility subsidiary of FirstEnergy. CEI conducts business
        in
        portions of Ohio, providing regulated electric distribution services. CEI
        also
        provides generation services to those customers electing to retain CEI as
        their
        power supplier. CEI’s power supply requirements are primarily provided by FES - an affiliated
        company.
 
 **FirstEnergy
        Intra-System Generation Asset Transfers**
  In 2005, the Ohio Companies and Penn entered into certain agreements
        implementing a series of intra-system generation asset transfers that were
        completed in the fourth quarter of 2005. The asset transfers resulted in
        the
        respective undivided ownership interests of the Ohio Companies and Penn in
        FirstEnergy’s nuclear and non-nuclear generation assets being owned by NGC and
        FGCO, respectively. T he
        generating plant
        interests transferred did not include CEI’s leasehold interests in certain of
        the plants that are currently subject to sale and leaseback arrangements
        with
        non-affiliates.
  On October 24, 2005, CEI completed the intra-system transfer of non-nuclear
        generation assets to FGCO. Prior to the transfer, FGCO, as lessee under a
        Master
        Facility Lease with the Ohio Companies and Penn, leased, operated and maintained
        the non-nuclear generation assets that it now owns. The asset transfers were
        consummated pursuant to FGCO's purchase option under the Master Facility
        Lease.
  On
        December 16, 2005, CEI completed the intra-system transfer of 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 comparative earnings results with reductions in both revenues and
        expenses. Revenues are reduced due to the termination of certain arrangements
        with FES, under which CEI previously sold its nuclear-generated KWH to FES
        and
        leased its non-nuclear generation assets to FGCO, a subsidiary of FES. CEI’s
        expenses are lower due to the nuclear fuel and operating costs assumed by
        NGC as
        well as depreciation and property tax expenses assumed by FGCO and NGC related
        to the transferred generating assets. With respect to CEI's retained leasehold
        interests in the Bruce Mansfield Plant, CEI has continued the fossil generation
        KWH sales arrangement with FES and continues to be obligated on the applicable
        portion of expenses related to those interests. In addition, CEI receives
        interest income on associated company notes receivable from the transfer
        of its
        generation net assets. FES 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).
 
 
  92
  The
        effects on CEI’s
        results of operations in the second quarter and first six months of 2006
        compared to the same periods of 2005 from the generation asset transfers
        (also
        reflecting CEI's retained leasehold interests discussed above) are summarized
        in
        the following table:
 
 **Intra-System
                  Generation Asset Transfers****Income
                  Statement Effects**
              
              **Three
                  Months**
              
              
              **Six
                  Months****Increase
                  (Decrease)**
              
              ***(In
                  millions)***Revenues:Non-nuclear
                  generating units rent
              (a)
              $
              (14
              )
              
              $
              (29
              )Nuclear
                  generated KWH sales
              (b)
              
              (57
              )
              
              
              (110
              )Total
                  -
                  Revenues Effect
              
              
              (71
              )
              
              
              (139
              )Expenses:Fuel
                  costs -
                  nuclear
              (c)
              
              (8
              )
              
              
              (14
              )Nuclear
                  operating costs
              (c)
              
              (37
              )
              
              
              (95
              )Provision
                  for
                  depreciation
              (d)
              
              (13
              )
              
              
              (32
              )General
                  taxes
              (e)
              
              (4
              )
              
              
              (8
              )Total
                  -
                  Expenses Effect
              
              
              (62
              )
              
              
              (149
              )Operating
                  Income Effect
              
              
              (9
              )
              
              
              10Other
                  Income:Interest
                  income from notes receivable
              (f)
              
              14
              
              
              
              30Nuclear
                  decommissioning trust earnings
              (g)
              
              (2
              )
              
              
              (4
              )Capitalized
                  interest
              (h)
              
              (1
              )
              
              
              -Total
                  - Other
                  Income Effect
              
              
              11
              
              
              
              26Income
                  taxes
              (i)
              
              1
              
              
              
              15Net
                  Income
                  Effect
              
              $
              1
              
              
              $
              21(a)
                  Elimination of non-nuclear generation assets lease to
                  FGCO.(b)
                  Reduction
                  of nuclear generated wholesale KWH sales to FES.(c)
                  Reduction
                  of nuclear fuel and operating costs.(d)
                  Reduction
                  of depreciation expense and asset retirement obligation accretion
                  related
                  to generation assets.(e)
                  Reduction
                  of property tax expense on generation assets.(f)
                  Interest
                  income on associated company notes receivable from the transfer
                  of
                  generation net assets.(g)
                  Reduction
                  of earnings on nuclear decommissioning trusts.(h)
                  Reduction
                  of allowance for borrowed funds used during construction on nuclear
                  capital expenditures.(i)
                  Income tax
                  effect of the above adjustments.
 
 **Results
        of Operations**
  Earnings
        on common
        stock in the second quarter of 2006 increased to $91 million from $39 million
        in
        the second quarter of 2005. In the first six months of 2006, earnings on
        common
        stock increased to $163 million from $51 million in the same period of 2005.
        The
        increase in earnings in both 2006 periods resulted primarily from lower expenses
        and increased other income, partially offset by lower revenues. These changes
        reflected the effects of the generation asset transfer shown in the table
        above
        and the absence of the $2 million Davis-Besse fine in the first quarter of
        2005
        and the $8 million impact of the Ohio tax change implementation in the second
        quarter of 2005.
 
 *Revenues*
 
 Revenues
        decreased
        by $16 million or 3.6% in the second quarter of 2006 from the same period
        in
        2005. Excluding
        the
        effects of the generation asset transfers displayed above, revenues increased
        $55 million due to a $105 million increase in retail generation sales revenues
        and a $28 million reduction in customer shopping incentives, partially offset
        by
        a $62 million decrease in distribution revenues and a $19 million decrease
        in
        MSG wholesale sales. In the first six months of 2006 compared to the same
        period
        in 2005, revenues decreased by $42 million or 4.7%. Excluding the effects
        of the
        generation asset transfers discussed above, revenues increased $97 million
        due
        to a $193 million increase in retail generation sales revenues and a $47
        million
        reduction in customer shopping incentives, partially offset by a $106 million
        decrease in distribution revenues and a $37 million decrease in MSG wholesale
        sales.
 
 Non-affiliated
        wholesale sales revenues decreased by $19 million for the second quarter
        of 2006
        and $37 million for the first six months of 2006 compared with the same periods
        in 2005 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.
 
  93
  Changes
        in electric
        generation KWH sales and revenues
        in the
        second quarter and first six months of 2006 from the corresponding periods
        of
        2005 are summarized in the following table.
 
 **Changes
                  in Generation KWH Sales**
              
              **Three
                  Months**
              
              **Six
                  Months****Increase
                  (Decrease)**Electric
                  Generation:Retail
              
              
              50.7
              %
              
              48.5
              %Wholesale
              
              
              (74.0)
              %
              
              (71.4)
              %**Net
                  Decrease in Generation Sales**
              
              
              **(21.4)**
              **%**
              
              **(17.7)**
              **%**
 
 **Changes
                  in Generation Revenues**
              
              
              **Three
                  Months**
              
              
              **Six
                  Months****Increase
                  (Decrease)**
              
              
              ***(In
                  millions)***Retail
                  Generation:Residential
              
              $
              39
              
              $
              77Commercial
              
              
              38
              
              
              70Industrial
              
              
              28
              
              
              46Total
                  Retail
                  Generation
              
              
              105
              
              
              193Wholesale*
              
              
              (19
              )
              
              (37
              )**Net
                  Increase in Generation Revenues**
              
              **$**
              **86**
              
              **$**
              **156**
 
 *  Excludes
        impact of
        generation asset transfers related to nuclear generated KWH sales.
 
 Increased
        retail
        generation revenue as shown in the table above for the second quarter 2006
        compared with the same quarter of 2005 was due to increased KWH sales and
        higher
        unit prices. The higher unit prices for generation reflected the rate
        stabilization charge that became effective in the first quarter of 2006 under
        provisions of the RSP and RCP. The increase in generation KWH sales resulted
        from decreased customer shopping. Generation services provided by alternative
        suppliers as a percent of total sales delivered in CEI's service area decreased
        by: residential - 61.0 percentage points, commercial - 43.5 percentage points
        and industrial - 8.9 percentage points. The decreased shopping resulted from
        certain alternative energy suppliers terminating their supply arrangements
        with
        CEI's shopping customers in the fourth quarter of 2005.
 
 Increased
        retail
        generation revenues in the first six months of 2006 compared with the same
        period in 2005 were also due to increased KWH sales and the higher unit prices
        under provisions of the RSP and RCP. The increase in generation KWH sales
        reflected a similar decrease in customer shopping as discussed above. This
        resulted in similar percentage decreases in the first half of 2006 in generation
        services provided by alternative suppliers as a percentage of total sales
        deliveries in CEI's service area (residential - 60.0 percentage points,
        commercial - 41.1 percentage points and industrial - 7.6 percentage points).
 
 Changes
        in
        distribution KWH deliveries and revenues
        in the
        second quarter and first six months of 2006 from the corresponding periods
        of
        2005 are summarized in the following table.
 
 **Changes
                  in Distribution KWH Sales**
              
              **Three
                  Months**
              
              **Six
                  Months****Increase
                  (Decrease)**Distribution
                  Deliveries:Residential
              
              
              (5.6)
              %
              
              (3.8)
              %Commercial
              
              
              (2.7)
              %
              
              (4.3)
              %Industrial
              
              
              (1.5)
              %
              
              (2.6)
              %**Net
                  Decrease in Distribution Deliveries**
              
              
              **(2.8)**
              **%**
              
              **(3.3)**
              **%**
 
 **Changes
                  in Distribution Revenues**
              
              **Three
                  Months**
              
              **Six
                  Months****Increase
                  (Decrease)**
              
              ***(In
                  millions)***Residential
              
              $
              (16
              )
              $
              (21
              )Commercial
              
              
              (23
              )
              
              (45
              )Industrial
              
              
              (23
              )
              
              (40
              )**Net
                  Decrease in Distribution Revenues**
              
              **$**
              **(62**
              **)**
              **$**
              **(106**
              **)**
 
 Lower
        distribution
        revenues as shown in the table above in the second quarter and first six
        months
        of 2006 primarily
        reflected
        lower unit prices and decreased KWH deliveries. The lower unit prices reflected
        the completion of the generation-related transition cost recovery under CEI’s
        transition plan in 2005, partially offset by increased transmission rates
        to
        recover MISO costs beginning in 2006 (see Outlook -- Regulatory Matters).
        The lower
        KWH distribution deliveries to residential and commercial customers reflected
        the impact of milder weather conditions in the second quarter and first six
        months of 2006, compared to the same periods of 2005.
  94
  
 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 earnings,
        ceased in 2006, resulting in a $28 million revenue increase for the second
        quarter of 2006 and a $47 million increase for the first six months of 2006
        compared to the same periods of 2005, as discussed above.
 
 *Expenses*
 
 Total
        expenses
        decreased by $76 million in the second quarter and $174 million in the first
        six
        months of 2006 from the same periods 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:
 
 **Expenses
                  - Changes**
              
              **Three
                  Months**
              
              **Six
                  Months****Increase
                  (Decrease)**
              
              ***(In
                  millions)***Fuel
                  costs
              
              $
              -
              
              $
              1Purchased
                  power costs
              
              
              19
              
              
              20Other
                  operating costs
              
              
              (6
              )
              
              3Provision
                  for
                  depreciation
              
              
              (9
              )
              
              (4
              )Amortization
                  of regulatory assets
              
              
              (26
              )
              
              (48
              )Deferral
                  of
                  new regulatory assets
              
              
              9
              
              
              4General
                  taxes
              
              
              (1
              )
              
              (1
              )**Net
                  decrease in expenses**
              
              $
              (14
              )
              $
              (25
              )
 
 Higher purchased
        power
        costs in the second quarter and in the first six months of 2006 compared
        with
        the same periods in 2005 primarily reflected increases in KWH purchased to
        meet
        higher retail generation sales requirements. These increases were partially
        offset by the impact of lower unit prices associated with the new power supply
        agreement with FES and purchased power lease credit amortizations of $8 million
        and $16 million in the second quarter and the first six months of 2006,
        respectively. 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. Lower other operating costs in the second quarter
        of 2006
        compared with the same period in 2005 reflected the absence in 2006 of
        transmission expenses related to the 2005 competitive retail energy supplier
        reimbursements which were discontinued at the end of 2005. Higher other
        operating costs in the first six months of 2006 compared with the same period
        in
        2005 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, the
        decrease in
        depreciation in the second quarter and first six months of 2006 compared
        with
        the same periods of 2005 was primarily attributable to a second quarter 2006
        pretax credit adjustment of $6.5 million ($4 million net of tax) applicable
        to
        prior periods. Lower
        amortization
        of regulatory assets in both periods of 2006 reflected the completion of
        generation-related transition cost amortization under CEI’s transition plan,
        partially offset by the amortization of deferred MISO costs that are being
        recovered in 2006. The
        decreased
        deferral of new regulatory assets in the second quarter and first six months
        of
        2006 compared with the same periods in 2005 was primarily due to the termination
        of the shopping incentive deferrals ($28 million and $47 million, respectively)
        and lower deferred MISO costs ($6 million and $5 million, respectively),
        partially offset by the deferrals of distribution costs ($14 million and
        $29
        million, respectively) and fuel costs ($11 million and $19 million,
        respectively) under the RCP.
 
 *Other
        Income*
 
 The
        increase in
        other income of $14 million in the second quarter and $32 million in the
        first
        six months of 2006 compared with the same periods last year 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 for the second quarter and first six months of 2006 by $2
        million and $7 million, respectively. The increase in both periods was primarily
        due to a $6 million benefit recognized in the second quarter of 2006 related
        to
        the sale of the Ashtabula C Plant, partially offset by increased interest
        expense in 2006 in both periods due to the absence of financing cost reductions
        recognized in 2005 related to refinancing activities.
 
 *Income
        Taxes*
 
 Increased
        income
        taxes in the second quarter and in the first six months of 2006 compared
        with
        the same periods 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 and the absence of a second quarter
        2005
        addition to income taxes of approximately $8 million, from the implementation
        of
        the Ohio tax legislation.
  95
  
 *Preferred
        Stock
        Dividend Requirements*
 
 Preferred
        stock
        dividend requirements decreased by $3 million in the first six months of
        2006,
        compared to the same period last year as a result of the optional redemption
        of
        CEI's remaining outstanding preferred stock in 2005.
 
 **Capital
        Resources and Liquidity**
  During 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 June 30, 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 six months of 2006, compared with the
        same
        period last year, were as follows:
 
 **Six
                  Months Ended**
                **June
                  30,****Operating
                  Cash Flows**
              
              **2006**
              
              **2005*****(In
                  millions)***Cash
                  earnings
                  *
              
              $
              125
              
              $
              113Working
                  capital and other
              
              
              34
              
              
              (36
              )Net
                  cash
                  provided from operating activities
              
              $
              159
              
              $
              77
 
 * Cash
        earnings are a
        non-GAAP measure (see reconciliation below).
 
 Cash
        earnings (in
        the table above) are not a measure of performance calculated in accordance
        with
        GAAP. CEI believes that cash earnings 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:
 
 **Six
                  Months Ended****June
                  30,****Reconciliation
                  of Cash Earnings**
              
              **2006**
              
              **2005*****(In
                  millions)***Net
                  Income
                  (GAAP)
              
              $
              163
              
              $
              54Non-cash
                  charges (credits):Provision
                  for
                  depreciation
              
              
              28
              
              
              65Amortization
                  of regulatory assets
              
              
              61
              
              
              109Deferral
                  of
                  new regulatory assets
              
              
              (62
              )
              
              (66
              )Nuclear
                  fuel
                  and capital lease amortization
              
              
              -
              
              
              11Amortization
                  of electric service obligation
              
              
              (7
              )
              
              (10
              )Deferred
                  rents
                  and lease market valuation liability
              
              
              (55
              )
              
              (54
              )Deferred
                  income taxes and investment tax credits, net
              
              
              (5
              )
              
              5Accrued
                  compensation and retirement benefits
              
              
              2
              
              
              (1
              )Cash
                  earnings
                  (Non-GAAP)
              
              $
              125
              
              $
              113
 
 Net
        cash provided
        from operating activities increased by $82 million in the first six months
        of
        2006 from the same period last year as a result of a $12 million increase
        in
        cash earnings described above under "Results of Operations" and a $70 million
        increase from working capital and other cash flows. The largest factors
        contributing to the changes in working capital and other operating cash flows
        for the first six months of 2006 are changes in accounts receivable related
        to the 2005
        conversion of the CFC receivables financing ($155 million) to on-balance
        sheet
        transactions, offset
        in part by
        changes in accounts payable and the absence of funds received in 2005 for
        prepaid electric service under the Energy for Education
        Program.
  96
  
 *Cash
        Flows from
        Financing Activities*
 
 Net
        cash used for
        financing activities increased by $141 million in the first six months of
        2006
        from the same period last year. The increase in funds used for financing
        activities primarily resulted from a $129 million increase in net preferred
        stock and debt redemptions and the absence of a $75 million equity contribution
        from FirstEnergy in 2005, partially offset by a $61 million decrease in common
        stock dividend payments to FirstEnergy.
 
 CEI
        had $29 million
        of cash and temporary investments (which included short-term notes receivable
        from associated companies) and approximately $304 million of short-term
        indebtedness as of June 30, 2006. CEI has obtained authorization from the
        PUCO
        to incur short-term debt of up to $500 million (including the bank facility
        and utility money pool described below). As of June 30, 2006, CEI had the
        capability to issue $247 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 June 30, 2006. CEI has no restrictions on the
        issuance of preferred stock.
 
 CFC
        is a wholly
        owned subsidiary of CEI whose borrowings are secured by customer accounts
        receivable purchased from CEI and TE. CFC can borrow up to $200 million under
        a
        receivables financing arrangement. As a separate legal entity with separate
        creditors, CFC would have to satisfy its obligations to creditors before
        any of
        its remaining assets could be made available to CEI. As of June 30, 2006,
        the
        facility was drawn for $149 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 six months of 2006 was
        4.86%.
  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 or 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.
  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 June 30, 2006, CEI's debt to total capitalization as defined
        under the revolving credit facility was 49%.
  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.
  IIn
        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.
  97
  
 *Cash
        Flows from
        Investing Activities*
 
 Net
        cash provided
        from investing activities increased by $59 million in the first six months
        of
        2006 from the same period last year. The change was primarily due to increased
        loan repayments from associated companies and the absence of net investments
        in
        nuclear decommissioning trust funds due to the intra-system nuclear generation
        asset transfer.
 
 CEI’s
        capital
        spending for the last half of 2006 is expected to be approximately $58 million.
        These cash requirements are expected to be satisfied from internal cash and
        short-term credit arrangements. CEI’s capital spending for the period 2006-2010
        is expected to be approximately $620 million of which approximately $127
        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 June 30,
        2006, the present value of these operating lease commitments, net of trust
        investments, total $98 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 June 30, 2006 and December
        31, 2005, were $859 million and $862 million, respectively.
 
 On
        October 21, 2003
        the Ohio Companies filed their RSP case with the PUCO. On August 5, 2004,
        the
        Ohio Companies accepted the RSP as modified and approved by the PUCO in an
        August 4, 2004 Entry on Rehearing, subject to a CBP. The RSP was intended
        to
        establish generation service rates beginning January 1, 2006, in response
        to the
        PUCO’s concerns about price and supply uncertainty following the end of the Ohio
        Companies' transition plan market development period. In October 2004, the
        OCC
        and NOAC filed appeals with the Supreme Court of Ohio to overturn the original
        June 9, 2004 PUCO order in the proceeding as well as the associated entries
        on
        rehearing. On September 28, 2005, the Supreme Court of Ohio heard oral arguments
        on the appeals. On May 3, 2006, the Supreme Court of Ohio issued an opinion
        affirming the PUCO's order with respect to the approval of the rate
        stabilization charge, approval of the shopping credits, the granting of interest
        on shopping credit incentive deferral amounts, and approval of the Ohio
        Companies’ financial separation plan. It remanded one matter back to the PUCO
        for further consideration of the issue as to whether the RSP, as adopted
        by the
        PUCO, provided for sufficient means for customer participation in the
        competitive marketplace. On May 12, 2006, the Ohio Companies filed a Motion
        for
        Reconsideration with the Supreme Court of Ohio which was denied by the Court
        on
        June 21, 2006. The RSP contained a provision that permitted the Ohio Companies
        to withdraw and terminate the RSP in the event that the PUCO, or the Supreme
        Court of Ohio, rejected all or part of the RSP. In such event, the Ohio
        Companies have 30 days from the final order or decision to provide notice
        of
        termination. On July 20, 2006 the Ohio Companies filed with the PUCO a Request
        to Initiate a Proceeding on Remand. In their Request, the Ohio Companies
        provided notice of termination to those provisions of the RSP subject to
        termination, subject to being withdrawn, and also set forth a framework for
        addressing the Supreme Court of Ohio’s findings on customer participation,
        requesting the PUCO to initiate a proceeding to consider the Ohio Companies’
proposal. If the PUCO approves a resolution to the issues raised by the Supreme
        Court of Ohio that is acceptable to the Ohio Companies, the Ohio Companies’
termination will be withdrawn and considered to be null and void. Separately,
        the OCC and NOAC also submitted to the PUCO on July 20, 2006 a conceptual
        proposal dealing with the issue raised by the Supreme Court of Ohio. On July
        26,
        2006, the PUCO issued an Entry acknowledging the July 20, 2006 filings of
        the
        Ohio Companies and the OCC and NOAC, and giving the Ohio Companies 45 days
        to
        file a plan in a new docket to address the Court’s concern.
  98
  
 The
        Ohio Companies
        filed an application and stipulation with the PUCO on September 9, 2005 seeking
        approval of the RCP. On November 4, 2005, the Ohio Companies filed a
        supplemental stipulation with the PUCO, which constituted an additional
        component of the RCP filed on September 9, 2005. Major provisions of the
        RCP
        include:
 
 ·
              Maintaining
                  the existing level of base distribution rates through April 30, 2009
                  for CEI;·
              Deferring
                  and
                  capitalizing for future recovery (over a 25-year period) with carrying
                  charges certain distribution costs to be incurred by all of the
                  Ohio
                  Companies during the period January 1, 2006 through December 31,
                  2008, not to exceed $150 million in each of the three
                  years;·
              Adjusting
                  the
                  RTC and extended RTC recovery periods and rate levels so that full
                  recovery of authorized costs will occur as of December 31, 2010 for
                  CEI;·
              Reducing
                  the
                  deferred shopping incentive balances as of January 1, 2006 by up to
                  $85 million for CEI by accelerating the application of its
                  accumulated cost of removal regulatory liability; and·
              Deferring
                  and
                  capitalizing (for recovery over a 25-year period) increased fuel
                  costs
                  above the amount collected through the Ohio Companies’ fuel recovery
                  mechanism.
 
 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
              
              $
              952007
              
              
              1132008
              
              
              1302009
              
              
              2112010
              
              
              266**Total
                  Amortization**
              
              **$**
              **815**
 
 On
        January 4, 2006,
        the PUCO approved, with modifications, the Ohio Companies’ RCP to supplement the
        RSP to provide customers with more certain rate levels than otherwise available
        under the RSP during the plan period. On
        January 10,
        2006, the Ohio Companies filed a Motion for Clarification of the PUCO order
        approving the RCP. The Ohio Companies sought clarity on issues related to
        distribution deferrals, including requirements of the review process, timing
        for
        recognizing certain deferrals and definitions of the types of qualified
        expenditures. The Ohio Companies also sought confirmation that the list of
        deferrable distribution expenditures originally included in the revised
        stipulation fall within the PUCO order definition of qualified expenditures.
        On
        January 25, 2006, the PUCO issued an Entry on Rehearing granting in part,
        and denying in part, the Ohio Companies’ previous requests and clarifying issues
        referred to above. The PUCO granted the Ohio Companies’ requests
        to:
 
 ·
              Recognize
                  fuel
                  and distribution deferrals commencing January 1,
                  2006;·
              Recognize
                  distribution deferrals on a monthly basis prior to review by the
                  PUCO
                  Staff;·
              Clarify
                  that
                  the types of distribution expenditures included in the Supplemental
                  Stipulation may be deferred; and·
              Clarify
                  that
                  distribution expenditures do not have to be “accelerated” in order to be
                  deferred.
 
 The
        PUCO approved
        the Ohio Companies’ methodology for determining distribution deferral amounts,
        but denied the Motion in that the PUCO Staff must verify the level of
        distribution expenditures contained in current rates, as opposed to simply
        accepting the amounts contained in the Ohio Companies’ Motion. On
        February 3, 2006, several other parties filed applications for rehearing on
        the PUCO's January 4, 2006 Order. The Ohio Companies responded to the
        applications for rehearing on February 8, 2006. In an Entry on Rehearing
        issued by the PUCO on March 1, 2006, all motions for rehearing were denied.
        Certain of these parties have subsequently filed notices of appeal with the
        Supreme Court of Ohio alleging various errors made by the PUCO in its order
        approving the RCP. The Ohio Companies’ Motion to Intervene in the appeals was
        granted by the Supreme Court on June 8, 2006. The Appellants’ Merit Briefs were
        filed at the Supreme Court on July 5, 2006. The Appellees include the PUCO
        and
        the Ohio Companies. The Appellees’ Merit Briefs are due on August 4, 2006.
        Appellants’ Reply Briefs will then be due on August 24, 2006.
  99
  
 On
        December 30,
        2004, CEI filed with the PUCO two applications related to the recovery of
        transmission and ancillary service related costs. The first application sought
        recovery of these costs beginning January 1, 2006. The Ohio Companies requested
        that these costs be recovered through a rider that would be effective on
        January 1, 2006 and adjusted each July 1 thereafter. The parties
        reached a settlement agreement that was approved by the PUCO on August 31,
        2005. The incremental transmission and ancillary service revenues recovered
        from
        January 1 through June 30, 2006 were approximately $23.5 million. That
        amount included the recovery of a portion of the 2005 deferred MISO expenses
        as
        described below. On May 1, 2006, CEI filed a modification to the rider to
        determine revenues ($51 million) 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. On January 20, 2006, the OCC sought rehearing
        of the PUCO’s approval of the recovery of deferred costs through the rider
        during the period January 1, 2006 through June 30, 2006. The PUCO
        denied the OCC's application on February 6, 2006. On March 23, 2006,
        the OCC appealed the PUCO's order to the Ohio Supreme Court. On March 27,
        2006, the OCC filed a motion to consolidate this appeal with the deferral
        appeals discussed above and to postpone oral arguments in the deferral appeal
        until after all briefs are filed in this most recent appeal of the rider
        recovery mechanism. On March 20, 2006, the Ohio Supreme Court, on its own
        motion, consolidated the OCC's appeal of CEI’s case with a similar case
        involving Dayton Power & Light Company. Oral arguments were heard on
        May 10, 2006. CEI is unable to predict when a decision may be
        issued.
  On
        November 1,
        2005, FES filed two power sales agreements for approval with the FERC. One
        power
        sales agreement provided for FES to provide the PLR requirements of the Ohio
        Companies at a price equal to the retail generation rates approved by the
        PUCO
        for a period of three years beginning January 1, 2006. The Ohio Companies
        will be relieved of their obligation to obtain PLR power requirements from
        FES
        if the Ohio CBP results in a lower price for retail customers.
 
 On
        December 29,
        2005, the FERC issued an order setting the two power sales agreements for
        hearing. The order criticized the Ohio CBP, and required FES to submit
        additional evidence in support of the reasonableness of the prices charged
        in
        the power sales agreements. A pre-hearing conference was held on
        January 18, 2006 to determine the hearing schedule in this case. Under the
        procedural schedule, approved in this case, FES expected an initial decision
        to
        be issued in late January 2007. However, on July 14, 2006, the Chief Judge
        granted the joint motion of FES and the Trial Staff to appoint a settlement
        judge in this proceeding. The procedural schedule has been suspended pending
        negotiations among the parties.
 
 See
        Note 11 to
        the consolidated financial statements for further details and a complete
        discussion of regulatory matters in Ohio.
 
 *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 June 30, 2006, based on
        estimates of the total costs of cleanup, CEI’s proportionate responsibility for
        such costs and the financial ability of other unaffiliated entities to pay.
        Included in Other Noncurrent Liabilities are accrued liabilities aggregating
        approximately $2 million as of June 30, 2006.
 
 See
        Note 10(B)
        to the consolidated financial statements for further details and a complete
        discussion of environmental matters.
  100
  
 *Other
        Legal
        Proceedings*
 
 *Power
        Outages
        and Related Litigation-*
 
 On
        August 14,
        2003, various states and parts of southern Canada experienced widespread
        power
        outages. The outages affected approximately 1.4 million customers in
        FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s
        final report in April 2004 on the outages concluded, among other things,
        that
        the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically,
        the
        final report concluded, among other things, that the initiation of the
        August 14, 2003 power outages resulted from an alleged failure of both
        FirstEnergy and ECAR to assess and understand perceived inadequacies within
        the
        FirstEnergy system; inadequate situational awareness of the developing
        conditions; and a perceived failure to adequately manage tree growth in certain
        transmission rights of way. The Task Force also concluded that there was
        a
        failure of the interconnected grid's reliability organizations (MISO and
        PJM) to
        provide effective real-time diagnostic support. The final report is publicly
        available through the Department of Energy’s Web site (www.doe.gov). FirstEnergy
        believes that the final report does not provide a complete and comprehensive
        picture of the conditions that contributed to the August 14, 2003 power
        outages and that it does not adequately address the underlying causes of
        the
        outages. FirstEnergy remains convinced that the outages cannot be explained
        by
        events on any one utility's system. The final report contained 46
“recommendations to prevent or minimize the scope of future blackouts.”
Forty-five of those recommendations related to broad industry or policy matters
        while one, including subparts, related to activities the Task Force recommended
        be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct
        the
        causes of the August 14, 2003 power outages. FirstEnergy implemented
        several initiatives, both prior to and since the August 14, 2003 power
        outages, which were independently verified by NERC as complete in 2004 and
        were
        consistent with these and other recommendations and collectively enhance
        the
        reliability of its electric system. FirstEnergy’s implementation of these
        recommendations in 2004 included completion of the Task Force recommendations
        that were directed toward FirstEnergy. FirstEnergy is also proceeding with
        the
        implementation of the recommendations that were to be completed subsequent
        to
        2004 and will continue to periodically assess the FERC-ordered Reliability
        Study
        recommendations for forecasted 2009 system conditions, recognizing revised
        load
        forecasts and other changing system conditions which may impact the
        recommendations. Thus far, implementation of the recommendations has not
        required, nor is expected to require, substantial investment in new or material
        upgrades to existing equipment. The FERC or other applicable government agencies
        and reliability coordinators may, however, take a different view as to
        recommended enhancements or may recommend additional enhancements in the
        future
        as the result of adoption of mandatory reliability standards pursuant to
        the
        EPACT that could require additional material expenditures.
 
 FirstEnergy
        companies also are defending six separate complaint cases before the PUCO
        relating to the August 14, 2003 power 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. Three other pending PUCO complaint cases were filed by various
        insurance carriers either in their own name as subrogees or in the name of
        their
        insured. In each of these three cases, the carrier seeks reimbursement from
        various FirstEnergy companies (and, in one case, from PJM, MISO and American
        Electric Power Company, Inc., as well) for claims paid to insureds for
        damages allegedly arising as a result of the loss of power on August 14,
        2003. The listed insureds in these cases, in many instances, are not customers
        of any FirstEnergy company. The sixth case involves the claim of a non-customer
        seeking reimbursement for losses incurred when its store was burglarized
        on
        August 14, 2003. FirstEnergy filed a Motion to Dismiss on June 13, 2006. It
        is currently expected that this case will be summarily dismissed, although
        the
        Motion is still pending. 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 as a defendant; ruled that
        the
        U.S.-Canada Power System Outage Task Force Report was not admissible into
        evidence; and gave the plaintiffs additional time to amend their complaints
        to
        otherwise comply with the PUCO’s underlying order. Also, most
        complainants, along with the FirstEnergy companies, filed applications for
        rehearing with the PUCO over various rulings contained in the March 7, 2006
        order. On April 26, 2006, the PUCO granted rehearing to allow the insurance
        company claimants, as insurers, to prosecute their claims in their name so
        long
        as they also identify the underlying insured entities and the Ohio utilities
        that provide their service. The PUCO denied all other motions for rehearing.
        The
        plaintiffs in each case have since filed an amended complaint and the named
        FirstEnergy companies have answered and also have filed a motion to dismiss
        each
        action. These motions are pending. Additionally, on June 23, 2006, one of
        the
        insurance carrier complainants filed an appeal with the Ohio Supreme Court
        over
        the PUCO’s denial of their motion for rehearing on the issue of the
        admissibility of the Task Force Report and the dismissal of FirstEnergy Corp.
        as
        a respondent. Briefing is expected to be completed on this appeal by
        mid-September. It is unknown when the Supreme Court will rule on the appeal.
        No
        estimate of potential liability is available for any of these cases.
  101
  
 FirstEnergy
        is
        vigorously defending these actions, but cannot predict the outcome of any
        of
        these proceedings or whether any further regulatory proceedings or legal
        actions
        may be initiated against the Companies. Although unable to predict the impact
        of
        these proceedings, if FirstEnergy or its subsidiaries were ultimately determined
        to have legal liability in connection with these proceedings, it could have
        a
        material adverse effect on FirstEnergy's or its subsidiaries' financial
        condition, results of operations and cash flows.
 
 *Other
        Legal
        Matters*
 
 There
        are various
        lawsuits, claims (including claims for asbestos exposure) and proceedings
        related to CEI’s normal business operations pending against CEI and its
        subsidiaries. The other potentially material items not otherwise discussed
        above
        are described below.
 
 On
        October 20,
        2004, FirstEnergy was notified by the SEC that the previously disclosed informal
        inquiry initiated by the SEC's Division of Enforcement in September 2003
        relating to the restatements in August 2003 of previously reported results
        by
        FirstEnergy and the Ohio Companies, and the Davis-Besse extended outage,
        have
        become the subject of a formal order of investigation. The SEC's formal order
        of
        investigation also encompasses issues raised during the SEC's examination
        of
        FirstEnergy and the Companies under the now repealed PUHCA. Concurrent with
        this
        notification, FirstEnergy received a subpoena asking for background documents
        and documents related to the restatements and Davis-Besse issues. On
        December 30, 2004, FirstEnergy received a subpoena asking for documents
        relating to issues raised during the SEC's PUHCA examination. On August 24,
        2005, additional information was requested regarding Davis-Besse-related
        disclosures, which has been provided. FirstEnergy has cooperated fully with
        the
        informal inquiry and continues to do so with the formal investigation.
 
 The
        City of Huron
        filed a complaint against OE with the PUCO challenging the ability of electric
        distribution utilities to collect transition charges from a customer of a
        newly-formed municipal electric utility. The complaint was filed on May 28,
        2003, and OE timely filed its response on June 30, 2003. In a related
        filing, the Ohio Companies filed for approval with the PUCO of a tariff that
        would specifically allow the collection of transition charges from customers
        of
        municipal electric utilities formed after 1998. Both filings were consolidated
        for hearing and decision described above. An adverse ruling could negatively
        affect full recovery of transition charges by the utility. Hearings on the
        matter were held in August 2005. Initial briefs from all parties were filed
        on
        September 22, 2005 and reply briefs were filed on October 14, 2005. On
        May 10, 2006, the PUCO issued its Opinion and Order dismissing the City’s
        complaint and approving the related tariffs, thus affirming OE’s entitlement to
        recovery of its transition charges. The City of Huron filed an application
        for
        rehearing of the PUCO’s decision on June 9, 2006 and OE filed a memorandum
        in opposition to that application on June 19, 2006. The PUCO denied the
        City’s application for rehearing on June 28, 2006. The City of Huron has 60 days
        from the denial of rehearing to appeal the PUCO’s decision.
  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**
 
 *FIN
        48 -
“Accounting for Uncertainty in Income Taxes - an interpretation of FASB
        Statement No. 109.”*
 
 In
        June 2006, the
        FASB issued FIN 48 which clarifies the accounting for uncertainty in income
        taxes recognized in an enterprise’s financial statements in accordance with FASB
        Statement No. 109, “Accounting for Income Taxes.” This interpretation prescribes
        a recognition threshold and measurement attribute for the financial statement
        recognition and measurement of a tax position taken or expected to be taken
        on a
        tax return. This interpretation also provides guidance on derecognition,
        classification, interest, penalties, accounting in interim periods, disclosure
        and transition. The evaluation of a tax position in accordance with this
        interpretation will be a two-step process. The first step will determine
        if it
        is more likely than not that a tax position will be sustained upon examination
        and should therefore be recognized. The second step will measure a tax position
        that meets the more likely than not recognition threshold to determine the
        amount of benefit to recognize in the financial statements. This interpretation
        is effective for fiscal years beginning after December 15, 2006. CEI is
        currently evaluating the impact of this Statement.
 
  102
  **THE
                      TOLEDO EDISON COMPANY****CONSOLIDATED
                      STATEMENTS OF INCOME AND COMPREHENSIVE INCOME****(Unaudited)****Three
                      Months Ended**
                  
                  **Six
                      Months Ended****June
                      30,**
                  
                  **June
                      30,****2006**
                  
                  **2005**
                  
                  **2006**
                  
                  **2005****STATEMENTS
                      OF INCOME**
                  
                  ***(In
                      thousands)*****REVENUES**
                  
                  $
                  225,598
                  
                  $
                  259,109
                  
                  $
                  443,575
                  
                  $
                  500,864**EXPENSES:**Fuel
                  
                  
                  9,638
                  
                  
                  14,404
                  
                  
                  19,400
                  
                  
                  26,973Purchased
                      power
                  
                  
                  80,659
                  
                  
                  72,300
                  
                  
                  156,079
                  
                  
                  152,456Nuclear
                      operating costs
                  
                  
                  17,866
                  
                  
                  46,689
                  
                  
                  35,198
                  
                  
                  105,852Other
                      operating costs
                  
                  
                  39,718
                  
                  
                  41,311
                  
                  
                  80,143
                  
                  
                  75,659Provision
                      for
                      depreciation
                  
                  
                  8,240
                  
                  
                  15,209
                  
                  
                  16,337
                  
                  
                  29,889Amortization
                      of regulatory assets
                  
                  
                  22,117
                  
                  
                  33,231
                  
                  
                  46,573
                  
                  
                  68,096Deferral
                      of
                      new regulatory assets
                  
                  
                  (14,190
                  )
                  
                  (12,670
                  )
                  
                  (27,846
                  )
                  
                  (22,094
                  )General
                      taxes
                  
                  
                  12,253
                  
                  
                  13,620
                  
                  
                  25,184
                  
                  
                  27,801Total
                      expenses
                  
                  
                  176,301
                  
                  
                  224,094
                  
                  
                  351,068
                  
                  
                  464,632**OPERATING
                      INCOME**
                  
                  
                  49,297
                  
                  
                  35,015
                  
                  
                  92,507
                  
                  
                  36,232**OTHER
                      INCOME (EXPENSE):**Investment
                      income
                  
                  
                  8,945
                  
                  
                  8,188
                  
                  
                  18,725
                  
                  
                  17,072Miscellaneous
                      expense
                  
                  
                  (1,926
                  )
                  
                  (3,100
                  )
                  
                  (4,610
                  )
                  
                  (6,402
                  )Interest
                      expense
                  
                  
                  (4,364
                  )
                  
                  (2,941
                  )
                  
                  (8,674
                  )
                  
                  (9,977
                  )Capitalized
                      interest
                  
                  
                  344
                  
                  
                  188
                  
                  
                  558
                  
                  
                  (255
                  )Total
                      other
                      income
                  
                  
                  2,999
                  
                  
                  2,335
                  
                  
                  5,999
                  
                  
                  438**INCOME
                      TAXES**
                  
                  
                  19,924
                  
                  
                  29,674
                  
                  
                  37,128
                  
                  
                  28,629**NET
                      INCOME**
                  
                  
                  32,372
                  
                  
                  7,676
                  
                  
                  61,378
                  
                  
                  8,041**PREFERRED
                      STOCK DIVIDEND REQUIREMENTS**
                  
                  
                  1,161
                  
                  
                  2,211
                  
                  
                  2,436
                  
                  
                  4,422**EARNINGS
                      ON COMMON STOCK**
                  
                  $
                  31,211
                  
                  $
                  5,465
                  
                  $
                  58,942
                  
                  $
                  3,619**STATEMENTS
                      OF COMPREHENSIVE INCOME****NET
                      INCOME**
                  
                  $
                  32,372
                  
                  $
                  7,676
                  
                  $
                  61,378
                  
                  $
                  8,041**OTHER
                      COMPREHENSIVE INCOME (LOSS):**Unrealized
                      gain (loss) on available for sale securities
                  
                  
                  191
                  
                  
                  (501
                  )
                  
                  (947
                  )
                  
                  (2,184
                  )Income
                      tax
                      expense (benefit) related to othercomprehensive
                      income
                  
                  
                  69
                  
                  
                  (96
                  )
                  
                  (342
                  )
                  
                  (791
                  )Other
                      comprehensive income (loss), net of tax
                  
                  
                  122
                  
                  
                  (405
                  )
                  
                  (605
                  )
                  
                  (1,393
                  )**TOTAL
                      COMPREHENSIVE INCOME**
                  
                  $
                  32,494
                  
                  $
                  7,271
                  
                  $
                  60,773
                  
                  $
                  6,648The
                      preceding
                      Notes to Consolidated Financial Statements as they relate to
                      The Toledo
                      Edison Company are an integral part of these
                      statements.
  103
 
 **THE
                    TOLEDO EDISON COMPANY****CONSOLIDATED
                    BALANCE SHEETS****(Unaudited)****June
                    30,**
                
                **December
                    31,****2006**
                
                **2005*****(In
                    thousands)*****ASSETS****CURRENT
                    ASSETS:**Cash
                    and cash
                    equivalents
                
                $
                23
                
                $
                15Receivables-Customers
                
                
                782
                
                
                2,209Associated
                    companies
                
                
                39,407
                
                
                16,311Other
                
                
                2,998
                
                
                6,410Notes
                    receivable from associated companies
                
                
                45,747
                
                
                48,349Prepayments
                    and other
                
                
                5,135
                
                
                1,05994,092
                
                
                74,353**UTILITY
                    PLANT:**In
                    service
                
                
                852,572
                
                
                824,677Less
                    -
                    Accumulated provision for depreciation
                
                
                380,234
                
                
                372,845472,338
                
                
                451,832Construction
                    work in progress
                
                
                28,499
                
                
                33,920500,837
                
                
                485,752**OTHER
                    PROPERTY AND INVESTMENTS:**Long-term
                    notes receivable from associated companies
                
                
                382,733
                
                
                436,178Investment
                    in
                    lessor notes
                
                
                169,493
                
                
                178,798Nuclear
                    plant
                    decommissioning trusts
                
                
                59,126
                
                
                59,209Other
                
                
                1,843
                
                
                1,781613,195
                
                
                675,966**DEFERRED
                    CHARGES AND OTHER ASSETS:**Goodwill
                
                
                500,576
                
                
                501,022Regulatory
                    assets
                
                
                267,032
                
                
                287,095Prepaid
                    pension costs
                
                
                35,124
                
                
                35,566Property
                    taxes
                
                
                18,047
                
                
                18,047Other
                
                
                39,728
                
                
                24,164860,507
                
                
                865,894$
                2,068,631
                
                $
                2,101,965**LIABILITIES
                    AND CAPITALIZATION****CURRENT
                    LIABILITIES:**Currently
                    payable long-term debt
                
                $
                -
                
                $
                53,650Accounts
                    payable-Associated
                    companies
                
                
                30,571
                
                
                46,386Other
                
                
                4,256
                
                
                2,672Notes
                    payable
                    to associated companies
                
                
                136,571
                
                
                64,689Accrued
                    taxes
                
                
                53,092
                
                
                49,344Lease
                    market
                    valuation liability
                
                
                24,600
                
                
                24,600Other
                
                
                19,379
                
                
                40,049268,469
                
                
                281,390**CAPITALIZATION:**Common
                    stockholder's equity -Common
                    stock,
                    $5 par value, authorized 60,000,000 shares -39,133,887
                    shares outstanding
                
                
                195,670
                
                
                195,670Other
                    paid-in
                    capital
                
                
                473,908
                
                
                473,638Accumulated
                    other comprehensive income
                
                
                4,085
                
                
                4,690Retained
                    earnings
                
                
                223,370
                
                
                189,428Total
                    common
                    stockholder's equity
                
                
                897,033
                
                
                863,426Preferred
                    stock
                
                
                66,000
                
                
                96,000Long-term
                    debt
                
                
                237,691
                
                
                237,7531,200,724
                
                
                1,197,179**NONCURRENT
                    LIABILITIES:**Accumulated
                    deferred income taxes
                
                
                209,389
                
                
                221,149Accumulated
                    deferred investment tax credits
                
                
                11,419
                
                
                11,824Lease
                    market
                    valuation liability
                
                
                231,100
                
                
                243,400Retirement
                    benefits
                
                
                41,986
                
                
                40,353Asset
                    retirement obligation
                
                
                25,675
                
                
                24,836Deferred
                    revenues - electric service programs
                
                
                28,151
                
                
                32,606Other
                
                
                51,718
                
                
                49,228599,438
                
                
                623,396**COMMITMENTS
                    AND CONTINGENCIES (Note 10)**$
                2,068,631
                
                $
                2,101,965The
                    preceding
                    Notes to Consolidated Financial Statements as they relate to
                    The Toledo
                    Edison Company are an integral
                    part
                    of these balance sheets.
   104
 
  **THE
                        TOLEDO EDISON COMPANY****CONSOLIDATED
                        STATEMENTS OF CASH FLOWS****(Unaudited)****Six
                        Months Ended****June
                        30,****2006**
                    
                    **2005*****(In
                        thousands)*****CASH
                        FLOWS FROM OPERATING ACTIVITIES:**Net
                        income
                    
                    $
                    61,378
                    
                    $
                    8,041Adjustments
                        to
                        reconcile net income to net cash from operating
                        activities-Provision
                        for
                        depreciation
                    
                    
                    16,337
                    
                    
                    29,889Amortization
                        of regulatory assets
                    
                    
                    46,573
                    
                    
                    68,096Deferral
                        of
                        new regulatory assets
                    
                    
                    (27,846
                    )
                    
                    (22,094
                    )Nuclear
                        fuel
                        and capital lease amortization
                    
                    
                    -
                    
                    
                    8,134Deferred
                        rents
                        and lease market valuation liability
                    
                    
                    (45,843
                    )
                    
                    (44,466
                    )Deferred
                        income taxes and investment tax credits, net
                    
                    
                    (13,322
                    )
                    
                    8,193Accrued
                        compensation and retirement benefits
                    
                    
                    1,268
                    
                    
                    1,500Decrease
                        (increase) in operating assets-Receivables
                    
                    
                    (18,257
                    )
                    
                    12,539Materials
                        and
                        supplies
                    
                    
                    -
                    
                    
                    (5,912
                    )Prepayments
                        and other current assets
                    
                    
                    (4,076
                    )
                    
                    408Increase
                        (decrease) in operating liabilities-Accounts
                        payable
                    
                    
                    (14,231
                    )
                    
                    (74,371
                    )Accrued
                        taxes
                    
                    
                    3,748
                    
                    
                    10,509Accrued
                        interest
                    
                    
                    (222
                    )
                    
                    (196
                    )Electric
                        service prepayment programs
                    
                    
                    (4,454
                    )
                    
                    36,563Other
                    
                    
                    3,326
                    
                    
                    (8,588
                    )Net
                        cash
                        provided from operating activities
                    
                    
                    4,379
                    
                    
                    28,245**CASH
                        FLOWS FROM FINANCING ACTIVITIES:**New
                        Financing-Long-term
                        debt
                    
                    
                    -
                    
                    
                    45,000Short-term
                        borrowings, net
                    
                    
                    71,882
                    
                    
                    -Redemptions
                        and Repayments-Preferred
                        stock
                    
                    
                    (30,000
                    )
                    
                    -Long-term
                        debt
                    
                    
                    (53,650
                    )
                    
                    (46,933
                    )Short-term
                        borrowings, net
                    
                    
                    -
                    
                    
                    (96,381
                    )Dividend
                        Payments-Common
                        stock
                    
                    
                    (25,000
                    )
                    
                    (10,000
                    )Preferred
                        stock
                    
                    
                    (2,436
                    )
                    
                    (4,422
                    )Net
                        cash used
                        for financing activities
                    
                    
                    (39,204
                    )
                    
                    (112,736
                    )**CASH
                        FLOWS FROM INVESTING ACTIVITIES:**Property
                        additions
                    
                    
                    (29,361
                    )
                    
                    (32,168
                    )Loan
                        repayments from (loans to) associated companies, net
                    
                    
                    2,611
                    
                    
                    (4,001
                    )Collection
                        of
                        principal on long-term notes receivable
                    
                    
                    53,766
                    
                    
                    123,546Investments
                        in
                        lessor notes
                    
                    
                    9,305
                    
                    
                    11,895Proceeds
                        from
                        nuclear decommissioning trust fund sales
                    
                    
                    30,665
                    
                    
                    153,940Investments
                        in
                        nuclear decommissioning trust funds
                    
                    
                    (30,754
                    )
                    
                    (168,211
                    )Other
                    
                    
                    (1,399
                    )
                    
                    (510
                    )Net
                        cash
                        provided from investing activities
                    
                    
                    34,833
                    
                    
                    84,491Net
                        change in
                        cash and cash equivalents
                    
                    
                    8
                    
                    
                    -Cash
                        and cash
                        equivalents at beginning of period
                    
                    
                    15
                    
                    
                    15Cash
                        and cash
                        equivalents at end of period
                    
                    $
                    23
                    
                    $
                    15The
                        preceding
                        Notes to Consolidated Financial Statements as they relate
                        to The Toledo
                        Edison Company are an integral part of these
                        statements.
 105
  
 
 ***Report
        of Independent Registered Public Accounting Firm***
 
 
 
 
 
 
 
 
 
 To
        the Stockholder
        and Board of
 Directors
        of The
        Toledo Edison Company:
 
 We
        have reviewed the
        accompanying consolidated balance sheet of The Toledo Edison Company and
        its
        subsidiaries as of June 30, 2006, and the related consolidated statements
        of
        income and comprehensive income for each of the three-month and six-month
        periods ended June 30, 2006 and 2005 and the consolidated statement of cash
        flows for the six-month period ended June 30, 2006 and 2005. These interim
        financial statements are the responsibility of the Company’s
        management.
 
 We
        conducted our
        review in accordance with the standards of the Public Company Accounting
        Oversight Board (United States). A review of interim financial information
        consists principally of applying analytical procedures and making inquiries
        of
        persons responsible for financial and accounting matters. It is substantially
        less in scope than an audit conducted in accordance with the standards of
        the
        Public Company Accounting Oversight Board, the objective of which is the
        expression of an opinion regarding the financial statements taken as a whole.
        Accordingly, we do not express such an opinion.
 
 Based
        on our review,
        we are not aware of any material modifications that should be made to the
        accompanying consolidated interim financial statements for them to be in
        conformity with accounting principles generally accepted in the United States
        of
        America.
 
 We
        have previously
        audited, in accordance with the standards of the Public Company Accounting
        Oversight Board (United States), the consolidated balance sheet as of December
        31, 2005, and the related consolidated statements of income, capitalization,
        common stockholder’s equity, preferred stock, cash flows and taxes for the year
        then ended (not presented herein), and in our report [which contained references
        to the Company’s change in its method of accounting for asset retirement
        obligations as of January 1, 2003 as discussed in Note 2(G) and Note 11 to
        those
        consolidated financial statements and the Company’s change in its method of
        accounting for the consolidation of variable interest entities as of December
        31, 2003 as discussed in Note 6 to those consolidated financial statements]
        dated February 27, 2006, we expressed an unqualified opinion on those
        consolidated financial statements. In our opinion, the information set forth
        in
        the accompanying consolidated balance sheet as of December 31, 2005, is fairly
        stated in all material respects in relation to the consolidated balance sheet
        from which it has been derived.
 
 
 
 
 PricewaterhouseCoopers
        LLP
 Cleveland,
        Ohio
 August
        4,
        2006
 
 
  106
  **THE
        TOLEDO
        EDISON COMPANY**
 
 **MANAGEMENT’S
        DISCUSSION AND ANALYSIS OF**
 **RESULTS
        OF
        OPERATIONS AND FINANCIAL CONDITION**
 
 
 TE
        is a wholly owned
        electric utility subsidiary of FirstEnergy. TE conducts business in northwestern
        Ohio, providing regulated electric distribution services. TE also provides
        generation services to those customers electing to retain TE as their power
        supplier. TE’s power supply requirements are provided by FES - an affiliated
        company.
 
 **FirstEnergy
        Intra-System Generation Asset Transfers**
 
 In
        2005, the Ohio
        Companies and Penn entered into certain agreements implementing a series
        of
        intra-system generation asset transfers that were completed in the fourth
        quarter of 2005. The asset transfers resulted in the respective undivided
        ownership interests of the Ohio Companies and Penn in FirstEnergy’s nuclear and
        non-nuclear generation assets being owned by NGC and FGCO, respectively.
        The
        generating plant interests transferred did not include TE's leasehold interests
        in certain of the plants that are currently subject to sale and leaseback
        arrangements with non-affiliates.
 
 On
        October 24,
        2005, TE completed the intra-system transfer of non-nuclear generation assets
        to
        FGCO. Prior to the transfer, FGCO, as lessee under a Master Facility Lease
        with
        the Ohio Companies and Penn, leased, operated and maintained the non-nuclear
        generation assets that it now owns. The asset transfers were consummated
        pursuant to FGCO's purchase option under the Master Facility Lease.
 
 On
        December 16,
        2005, TE completed the intra-system transfer of its ownership interests in
        the
        nuclear generation assets to NGC through a sale at net book value. FENOC
        continues to operate and maintain the nuclear generation assets.
 
 These
        transactions
        were undertaken pursuant to the Ohio Companies’ and Penn’s restructuring plans
        that were approved by the PUCO and the PPUC, respectively, under applicable
        Ohio
        and Pennsylvania electric utility restructuring legislation. Consistent with
        the
        restructuring plans, generation assets that had been owned by the Ohio Companies
        and Penn were required to be separated from the regulated delivery business
        of
        those companies through transfer to a separate corporate entity. The
        transactions essentially completed the divestitures contemplated by the
        restructuring plans by transferring the ownership interests to NGC and FGCO
        without impacting the operation of the plants.
 
 The
        transfers affect
        TE’s comparative earnings results with reductions in both revenues and expenses.
        Revenues are reduced due to the termination of certain arrangements with
        FES,
        under which TE previously sold its nuclear-generated KWH to FES and leased
        its
        non-nuclear generation assets to FGCO, a subsidiary of FES. TE’s expenses are
        lower due to the nuclear fuel and operating costs assumed by NGC as well
        as
        depreciation and property tax expenses assumed by FGCO and NGC related to
        the
        transferred generating assets. With respect to TE's retained leasehold interests
        in the Bruce Mansfield Plant and Beaver Valley Unit 2, TE has continued the
        generation KWH sales arrangement with FES and its Beaver Valley Unit 2 leased
        capacity sales arrangement with CEI, and continues to be obligated on the
        applicable portion of expenses related to those interests. In addition, TE
        receives interest income on associated company notes receivable from the
        transfer of its generation net assets. FES 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).
  107
   The effects on TE’s results of operations in the second quarter and first six
        months of 2006 compared to the same periods of 2005 from the generation asset
        transfers are summarized in the following table:
 
 **Intra-System
                  Generation Asset Transfers -****Income
                  Statement Effects**
              
              **Three
                  Months**
              
              
              **Six
                  Months****Increase
                  (Decrease)**
              
              ***(In
                  millions)***Revenues:Non-nuclear
                  generating units rent
              (a)
              $
              (3
              )
              
              $
              (7
              )Nuclear
                  generated KWH sales
              (b)
              
              (29
              )
              
              
              (51
              )Total
                  -
                  Revenues Effect
              
              
              (32
              )
              
              
              (58
              )Expenses:Fuel
                  costs -
                  nuclear
              (c)
              
              (5
              )
              
              
              (8
              )Nuclear
                  operating costs
              (c)
              
              (22
              )
              
              
              (62
              )Provision
                  for
                  depreciation
              (d)
              
              (7
              )
              
              
              (16
              )General
                  taxes
              (e)
              
              (2
              )
              
              
              (3
              )Total
                  -
                  Expenses Effect
              
              
              (36
              )
              
              
              (89
              )Operating
                  Income Effect
              
              
              4
              
              
              
              31Other
                  Income:Interest
                  income from notes receivable
              (f)
              
              4
              
              
              
              8Nuclear
                  decommissioning trust earnings
              (g)
              
              (3
              )
              
              
              (4
              )Capitalized
                  interest
              (h)
              
              (1
              )
              
              
              -Total
                  - Other
                  Income Effect
              
              
              -
              
              
              
              4Income
                  taxes
              (i)
              
              1
              
              
              
              14Net
                  Income
                  Effect
              
              $
              3
              
              
              $
              21(a)
                  Elimination of non-nuclear generation assets lease to
                  FGCO.(b)
                  Reduction
                  of nuclear generated wholesale KWH sales to FES.(c)
                  Reduction
                  of nuclear fuel and operating costs.(d)
                  Reduction
                  of depreciation expense and asset retirement obligation accretion
                  related
                  to generation assets.(e)
                  Reduction
                  of property tax expense on generation assets.(f)
                  Interest
                  income on associated company notes receivable from the transfer
                  of
                  generation net assets.(g)
                  Reduction
                  of earnings on nuclear decommissioning trusts.(h)
                  Reduction
                  of allowance for borrowed funds used during construction on nuclear
                  capital expenditures.(i)
                  Income tax
                  effect of the above adjustments.
 
 **Results
        of Operations**
 
 Earnings
        on common
        stock in the second quarter of 2006 increased to $31 million from
        $5 million in the second quarter of 2005. This increase resulted primarily
        from reduced expenses and the absence of additional income taxes of $17.5
        million from the implementation of Ohio tax legislation changes in the second
        quarter of 2005, partially offset by lower revenues. Earnings
        on common
        stock in the first six months of 2006 increased to $59 million from
        $4 million in the first six months of 2005. This increase resulted
        primarily from reduced expenses, increased other income and the absence of
        the
        additional income taxes discussed above, also partially offset by lower
        revenues. The earnings increases for both periods included the effects of
        the
        generation asset transfer shown in the table above.
  *Revenues*
  Revenues decreased by $33 million or 12.9% in the second quarter of 2006
        compared with the same period of 2005, primarily due to the generation asset
        transfer impact displayed in the table above. Excluding the effects of the
        generation asset transfers, revenues decreased $1 million due to decreased
        distribution revenues of $34 million, partially offset by a $23 million increase
        in generation sales revenues, a $9 million reduction in customer shopping
        incentives and a $1 million increase in other revenues.
 
 In
        the first six
        months of 2006, revenues decreased by $57 million or 11.4% compared with
        the
        same period of 2005, primarily due to the generation asset transfer impact
        displayed in the table above. Excluding the effects of the generation asset
        transfers, revenues increased $1 million due to a $44 million increase in
        generation sales revenues, a $15 million reduction in customer shopping
        incentives and a $1 million increase in other revenues, partially offset
        by a
        $59 million decrease in distribution revenues.
  108
  Changes
        in electric
        generation KWH sales and revenues
        in the
        second quarter and first six months of 2006 from the corresponding periods
        of
        2005 are summarized in the following table.
 
 **Changes
                  in Generation KWH Sales**
              
              **Three
                  Months**
              
              **Six
                  Months****Increase
                  (Decrease)**Electric
                  Generation:Retail
              
              
              16.1
              %
              
              12.8
              %Wholesale
              
              
              (57.6
              )%
              
              (56.7
              )%**Net
                  Decrease in Generation Sales**
              
              
              **(24.5**
              **)%**
              
              **(23.8**
              **)%**
 
 **Changes
                  in Generation Revenues**
              
              **Three
                  Months**
              
              **Six
                  Months****Increase
                  (Decrease)**
              
              ***(In
                  millions)***Retail
                  Generation:Residential
              
              $
              17
              
              $
              32Commercial
              
              
              13
              
              
              22Industrial
              
              
              7
              
              
              9Total Retail Generation
              
              
              37
              
              
              63Wholesale*
              
              
              (14
              )
              
              (19
              )**Net
                  Increase in Generation Revenues**
              
              **$**
              **23**
              
              **$**
              **44**
  *
        Excludes impact of
        generation asset transfers related to nuclear generated KWH sales.
 
 Retail
        generation
        revenues increased in all customer sectors as shown in the table above in
        the
        second quarter of 2006 compared to the corresponding quarter of 2005 due
        to
        higher unit prices and increased KWH sales. The higher unit prices for
        generation reflected the rate stabilization charge and the fuel cost recovery
        rider that both became effective in the first quarter of 2006 under provisions
        of the RSP and RCP. The increase in generation KWH sales (residential - 52.5%,
        commercial - 15.5% and industrial - 7.1%) primarily resulted from decreased
        customer shopping. The decreased shopping resulted from certain alternative
        energy suppliers terminating their supply arrangements with TE's shopping
        customers in the first quarter of 2006. Generation services provided by
        alternative suppliers as a percentage of total sales delivered in TE's franchise
        area decreased in all customer classes by: residential - 34.4 percentage
        points ,
        commercial - 11.4 percentage points and
        industrial - 2 percentage
        points .
 
 In
        the first six
        months of 2006, retail generation revenues increased from the corresponding
        period of 2005 for the reasons described above. The decreased customer shopping
        resulted in generation KWH sales increases in all customer classes (residential
        - 44.1%, commercial - 13.6% and industrial - 3.8%). Similar to the second
        quarter of 2006, generation services provided by alternative suppliers as
        a
        percentage of total sales deliveries in TE's franchise area decreased in
        all
        customer classes by: residential - 29 percentage
        points ,
        commercial - 10 percentage points and
        industrial - 1.7 percentage
        points .
 
 Lower
        wholesale
        revenues in the second quarter and first six months of 2006 reflected decreased
        revenues from non-affiliates ($5 million and $8 million, respectively) and
        decreased revenues from associated companies ($9 million and $11 million,
        respectively). The non-affiliated wholesale revenue decreases in 2006 were
        primarily 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.  The
        lower wholesale
        revenues from associated companies in 2006 reflected lower unit prices due
        to
        this year’s absence of expenses related to the Beaver Valley Unit 2 nuclear
        refueling outage in April 2005, which were included as a component of the
        associated company billing for the 2005 period.
 
 Changes
        in
        distribution KWH deliveries and revenues
        in the
        second quarter and first six months of 2006 from the corresponding periods
        of
        2005 are summarized in the following table.
 
 
 **Changes
                  in Distribution KWH Deliveries**
              
              **Three
                  Months**
              
              **Six
                  Months****Increase
                  (Decrease)**Distribution
                  Deliveries:Residential
              
              
              (6.6
              )%
              
              (3.8
              )%Commercial
              
              
              (5.1
              )%
              
              (4.4
              )%Industrial
              
              
              4.9
              %
              
              1.9
              %**Net
                  Decrease in Distribution Deliveries**
              
              
              **(0.5**
              **)%**
              
              **(1.2**
              **)%**
 
  109
  
 **Changes
                  in Distribution Revenues**
              
              **Three
                  Months**
              
              **Six
                  Months****Increase
                  (Decrease)**
              
              ***(In
                  millions)***Residential
              
              $
              (14
              )
              $
              (25
              )Commercial
              
              
              (16
              )
              
              (29
              )Industrial
              
              
              (4
              )
              
              (5
              )**Net
                  Decrease in Distribution Revenues**
              
              **$**
              **(34**
              **)**
              **$**
              **(59**
              **)**
  The
        distribution
        revenue decreases as shown in the table above in the second quarter and first
        six months of 2006 compared to the same periods of 2005 primarily reflected
        lower unit prices in all customer sectors and decreased KWH deliveries to
        residential and commercial customers. The lower unit prices reflected the
        completion of the generation-related transition cost recovery under TE’s
        transition plan in 2005, partially offset by increased transmission rates
        to
        recover MISO costs beginning in the first quarter of 2006 (see Outlook -
        Regulatory Matters). The lower
        KWH
        distribution deliveries to residential and commercial customers in both periods
        reflected the impact of milder weather in the second quarter and the first
        six
        months of 2006 compared to the same periods of 2005. KWH
        deliveries to
        industrial customers increased in both periods of 2006 due to increased sales
        to
        automotive, oil refinery and steel industry customers.
 
 Under
        the Ohio
        transition plan, TE had provided incentives to customers to encourage switching
        to alternative energy providers which reduced TE's revenues. These revenue
        reductions, which were deferred for future recovery and did not affect current
        period earnings, ceased in 2006 thereby increasing revenues in the second
        quarter and first six months of 2006 by $9 million and $15 million,
        respectively. The deferred shopping incentives (Extended RTC) are currently
        being recovered under the RCP (see Outlook - Regulatory Matters).
 
 *Expenses*
 
 Total
        expenses
        decreased by $48 million and $114 million in the second quarter and the first
        six months of 2006, respectively, from the same periods of 2005 principally
        due
        to the generation asset transfer effects as shown in the table above. Excluding
        the asset transfer effects, the following table presents changes from the
        prior
        year by expense category:
 
 **Expenses
                  - Changes**
              
              **Three
                  Months**
              
              **Six
                  Months****Increase
                  (Decrease)**
              
              ***(In
                  millions)***Fuel
              
              $
              -
              
              $
              1Purchased
                  power costs
              
              
              8
              
              
              4Nuclear
                  operating costs
              
              
              (6
              )
              
              (9
              )Other
                  operating costs
              
              
              (1
              )
              
              4Provision
                  for
                  depreciation
              
              
              -
              
              
              2Amortization
                  of regulatory assets
              
              
              (11
              )
              
              (21
              )Deferral
                  of
                  new regulatory assets
              
              
              (2
              )
              
              (6
              )**Net
                  decrease in expenses**
              
              $
              (12
              )
              $
              (25
              )
 
 Higher
        purchased
        power costs in the second quarter of 2006 compared to the second quarter
        of 2005
        primarily reflected an increase in KWH purchased to meet the higher retail
        generation sales requirements and higher unit prices associated with the
        new
        power supply agreement with FES. Decreased nuclear operating costs in the
        2006
        quarter were due to lower costs associated with TE’s leasehold interest in
        Beaver Valley Unit 2. The decrease reflected the absence in 2006 of expenses
        in
        the second quarter of 2005 related to Beaver Valley Unit 2’s 25-day nuclear
        refueling outage in April 2005.
 
 Higher
        purchased
        power costs in the first six months of 2006 compared to the same period of
        2005
        reflected an increase in KWH purchased to meet higher retail generation sales
        requirements, partially offset by lower unit prices. The nuclear operating
        costs
        decrease in the first six months of 2006 was due to the reasons described
        above
        for the second quarter. 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 in the first
        six
        months of 2006 increased due to distribution plant additions.
  110
  
 Lower
        amortization
        of regulatory assets in both periods of 2006 reflected the completion of
        generation-related transition cost recovery under TE’s transition plan,
        partially offset by the amortization of deferred MISO costs that are being
        recovered in 2006. The net change in deferrals of new regulatory assets in
        the
        second quarter and first six months of 2006 primarily resulted from the
        deferrals of distribution costs ($7 million and $13 million in the second
        quarter and the first six months of 2006, respectively) and incremental fuel
        costs ($4 million and $7 million in the second quarter and the first six
        months
        of 2006, respectively) that began in 2006 under the RCP, partially offset
        by the
        impact of the termination of shopping incentive deferrals in 2006
        ($9 million and $16 million in the second quarter and the first six months
        of 2006, respectively).
  *Other
        Income*
 
 Other
        income
        increased $5 million in the first six months of 2006 compared to the same
        period
        of 2005, primarily due to the effects of the generation asset transfers.
        Excluding the asset transfer effects, the $1 million increase reflected lower
        net interest charges and the absence of a charge of $1.6 million for an NRC
        fine
        related to Davis-Besse Plant in the first quarter of 2005, partially offset
        by
        the absence of interest income on a note from FGCO, which had a balloon
        repayment in May 2005.
 
 *Income
        Taxes*
 
 Income
        taxes
        decreased $10 million in the second quarter of 2006 and increased by $8 million
        in the first six months of 2006 compared to the same periods of 2005. Excluding
        the effects of the generation asset transfer, income taxes decreased in the
        second quarter and first six months of 2006 by $11 million and $6 million,
        respectively. These decreases were primarily due to the absence in 2006 of
        $17.5
        million of additional income tax expenses from the implementation of Ohio
        tax
        legislation changes in the second quarter of 2005 and the subsequent reduction
        in the tax rates, partially offset by the effect of increases in taxable
        income.
 
 *Preferred
        Stock
        Dividend Requirements*
 
 Lower
        preferred
        stock dividend requirements in the second quarter and first six months of
        2006
        compared to the corresponding 2005 periods were the result of $60 million
        of
        optional preferred stock redemptions subsequent to the end of the second
        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 $300 million of new
        long-term debt in 2006 with proceeds expected to fund a return of equity
        capital
        to FirstEnergy.
 
 *Changes
        in Cash
        Position*
 
 As
        of June 30, 2006,
        TE had $23,000 of cash and cash equivalents, compared with $15,000 as of
        December 31, 2005. The major changes in these balances are summarized below.
 
 *Cash
        Flows From
        Operating Activities*
 
 Cash
        provided from
        operating activities during the first six months of 2006, compared with the
        first six months of 2005, were as follows:
 
 
 **Six
                  Months Ended****June
                  30,****Operating
                  Cash Flows**
              
              **2006**
              
              **2005*****(In
                  millions***)Cash
                  earnings*
              
              $
              34
              
              $
              56Working
                  capital and other
              
              
              (30
              )
              
              (28
              )Net
                  cash
                  provided from operating activities
              
              $
              4
              
              $
              28*Cash
                  earnings are 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. 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:
  **Six
                  Months Ended**
                **June
                  30,****Reconciliation
                  of Cash Earnings**
              
              **2006**
              
              **2005*****(In
                  millions)***Net
                  Income
                  (GAAP)
              
              $
              61
              
              $
              8Non-Cash
                  Charges (Credits):Provision
                  for
                  depreciation
              
              
              16
              
              
              30Amortization
                  of regulatory assets
              
              
              47
              
              
              68Deferral
                  of
                  new regulatory assets
              
              
              (28
              )
              
              (22
              )Nuclear
                  fuel
                  and capital lease amortization
              
              
              -
              
              
              8Amortization
                  of electric service obligation
              
              
              (4
              )
              
              (1
              )Deferred
                  rents
                  and lease market valuation liability
              
              
              (46
              )
              
              (44
              )Deferred
                  income taxes and investment tax credits, net
              
              
              (13
              )
              
              8Accrued
                  compensation and retirement benefits
              
              
              1
              
              
              1Cash
                  earnings
                  (Non-GAAP)
              
              $
              34
              
              $
              56
 
 Net
        cash provided
        from operating activities decreased by $24 million in the first six months
        of
        2006 from the first six months of 2005 as a result of a $22 million decrease
        in
        cash earnings described above under “Results of Operations” and a
        $2 million decrease from working capital and other changes. The decrease in
        working capital and other primarily resulted from the absence in 2006 of
        funds
        received in 2005 for a prepaid electric service program and a reduction in
        cash
        received from the settlement of receivables, partially offset by lower cash
        payments on accounts payable.
 
 *Cash
        Flows From
        Financing Activities*
 
 Net
        cash used for
        financing activities decreased to $39 million in the first six months of
        2006
        from $113 million in the same period of 2005. The decrease resulted primarily
        from a $168 million increase in net short-term borrowings, partially offset
        by
        an $82 million net increase in preferred stock and long-term debt redemptions
        and a $15 million increase in common stock dividend payments to FirstEnergy
        in
        2006.
  TE
        had $46 million of cash and temporary investments (which included short-term
        notes receivable from associated companies) and $137 million of short-term
        indebtedness as of June 30, 2006. TE has authorization from the PUCO to incur
        short-term debt of up to $500 million through the bank facility and utility
        money pool described below. As of June 30, 2006, TE had the capability to
        issue
        $634 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 $1.1 billion of preferred stock (assuming
        no additional debt) was issued as of June 30, 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 mature on
        the
        earlier of 364 days from the date of borrowing or 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 June 30, 2006, TE's debt to total capitalization, as
        defined under the revolving credit facility, was 28%.
  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.
 
 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 six months of 2006 was 4.86%.
  112
  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 provided from investing activities decreased by $50 million in the first
        six months of 2006 from the same period of 2005 primarily due to a d ecrease
        in the
        collection of principal on long-term notes receivable. This resulted from
        the
        receipt in April 2006 of $54 million from FGCO and NGC following the pollution
        control notes refinancing discussed above as compared to the receipt in May
        2005
        of a $123 million balloon payment from FGCO for gas-fired combustion turbines
        sold in 2001. This decrease in cash receipts was partially offset by reduced
        property additions and net activity for the nuclear decommissioning trust
        funds
        due to the generation asset transfers.
  TE’s capital spending for the last half of 2006 is expected to be approximately
        $29 million. These cash requirements are expected to be satisfied from a
        combination of internal cash and short-term credit arrangements. TE’s capital
        spending for the period 2006-2010 is expected to be approximately
        $232 million, of which approximately $58 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 June 30, 2006, the present value of these operating lease
        commitments, net of trust investments, totaled $498 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 June 30, 2006 and
        December 31, 2005 were $267 million and $287 million,
        respectively.
  113
  
 On
        October 21, 2003
        the Ohio Companies filed their RSP case with the PUCO. On August 5, 2004,
        the
        Ohio Companies accepted the RSP as modified and approved by the PUCO in an
        August 4, 2004 Entry on Rehearing, subject to a CBP. The RSP was intended
        to
        establish generation service rates beginning January 1, 2006, in response
        to the
        PUCO’s concerns about price and supply uncertainty following the end of the Ohio
        Companies' transition plan market development period. In October 2004, the
        OCC
        and NOAC filed appeals with the Supreme Court of Ohio to overturn the original
        June 9, 2004 PUCO order in the proceeding as well as the associated entries
        on
        rehearing. On September 28, 2005, the Supreme Court of Ohio heard oral arguments
        on the appeals. On May 3, 2006, the Supreme Court of Ohio issued an opinion
        affirming the PUCO's order with respect to the approval of the rate
        stabilization charge, approval of the shopping credits, the granting of interest
        on shopping credit incentive deferral amounts, and approval of the Ohio
        Companies’ financial separation plan. It remanded one matter back to the PUCO
        for further consideration of the issue as to whether the RSP, as adopted
        by the
        PUCO, provided for sufficient means for customer participation in the
        competitive marketplace. On May 12, 2006, the Ohio Companies filed a Motion
        for
        Reconsideration with the Supreme Court of Ohio which was denied by the Court
        on
        June 21, 2006. The RSP contained a provision that permitted the Ohio Companies
        to withdraw and terminate the RSP in the event that the PUCO, or the Supreme
        Court of Ohio, rejected all or part of the RSP. In such event, the Ohio
        Companies have 30 days from the final order or decision to provide notice
        of
        termination. On July 20, 2006 the Ohio Companies filed with the PUCO a Request
        to Initiate a Proceeding on Remand. In their Request, the Ohio Companies
        provided notice of termination to those provisions of the RSP subject to
        termination, subject to being withdrawn, and also set forth a framework for
        addressing the Supreme Court of Ohio’s findings on customer participation,
        requesting the PUCO to initiate a proceeding to consider the Ohio Companies’
proposal. If the PUCO approves a resolution to the issues raised by the Supreme
        Court of Ohio that is acceptable to the Ohio Companies, the Ohio Companies’
termination will be withdrawn and considered to be null and void. Separately,
        the OCC and NOAC also submitted to the PUCO on July 20, 2006 a conceptual
        proposal dealing with the issue raised by the Supreme Court of Ohio. On July
        26,
        2006, the PUCO issued an Entry acknowledging the July 20, 2006 filings of
        the
        Ohio Companies and the OCC and NOAC, and giving the Ohio Companies 45 days
        to
        file a plan in a new docket to address the Court’s concern.
  The Ohio Companies filed an application and stipulation with the PUCO on
        September 9, 2005 seeking approval of the RCP. On November 4, 2005, the Ohio
        Companies filed a supplemental stipulation with the PUCO, which constituted
        an
        additional component of the RCP filed on September 9, 2005. Major provisions
        of
        the RCP include:
 
 ·
              Maintaining
                  the existing level of base distribution rates through December 31,
                  2008 for TE;
 
 ·
              Deferring
                  and
                  capitalizing for future recovery (over a 25-year period) with carrying
                  charges certain distribution costs to be incurred by all the Ohio
                  Companies during the period January 1, 2006 through December 31,
                  2008, not to exceed $150 million in each of the three
                  years;
 
 ·
              Adjusting
                  the
                  RTC and extended RTC recovery periods and rate levels so that full
                  recovery of authorized costs will occur as of December 31, 2008 for
                  TE;
 
 ·
              Reducing
                  the
                  deferred shopping incentive balances as of January 1, 2006 by up to
                  $45 million for TE by accelerating the application of its accumulated
                  cost of removal regulatory liability;
                  and
 
 ·
              Recovering
                  increased fuel costs (compared to a 2002 baseline) of up to $75
                  million,
                  $77 million, and $79 million, in 2006, 2007, and 2008,
                  respectively, from all OE and TE distribution and transmission
                  customers
                  through a fuel recovery mechanism. OE, TE, and CEI may defer and
                  capitalize (for recovery over a 25-year period) increased fuel
                  costs above
                  the amount collected through the fuel recovery mechanism.
  The following table provides TE’s estimated amortization of regulatory
        transition costs and deferred shopping incentives (including associated carrying
        charges) under the RCP for the period 2006 through 2008:
 
 **Amortization**
                **Period**
              
              **Amortization*****(In
                  millions)***2006
              
              $
              862007
              
              
              902008
              
              
              111**Total
                  Amortization**
              
              **$**
              **287**
 
   114
   On
        January 4, 2006, the PUCO approved, with modifications, the Ohio Companies’ RCP
        to supplement the RSP to provide customers with more certain rate levels
        than
        otherwise available under the RSP during the plan period. On January 10,
        2006, the Ohio Companies filed a Motion for Clarification of the PUCO order
        approving the RCP. The Ohio Companies sought clarity on issues related to
        distribution deferrals, including requirements of the review process, timing
        for
        recognizing certain deferrals and definitions of the types of qualified
        expenditures. The Ohio Companies also sought confirmation that the list of
        deferrable distribution expenditures originally included in the revised
        stipulation fall within the PUCO order definition of qualified expenditures.
        On
        January 25, 2006, the PUCO issued an Entry on Rehearing granting in part,
        and denying in part, the Ohio Companies’ previous requests and clarifying issues
        referred to above. The PUCO granted the Ohio Companies’ requests to:
 
 ·
              Recognize
                  fuel
                  and distribution deferrals commencing January 1,
                  2006;·
              Recognize
                  distribution deferrals on a monthly basis prior to review by the
                  PUCO
                  Staff;·
              Clarify
                  that
                  the types of distribution expenditures included in the Supplemental
                  Stipulation may be deferred; and·
              Clarify
                  that
                  distribution expenditures do not have to be “accelerated” in order to be
                  deferred.
   The
        PUCO approved the Ohio Companies’ methodology for determining distribution
        deferral amounts, but denied the Motion in that the PUCO Staff must verify
        the
        level of distribution expenditures contained in current rates, as opposed
        to
        simply accepting the amounts contained in the Ohio Companies’ Motion. On
        February 3, 2006, several other parties filed applications for rehearing on
        the PUCO's January 4, 2006 Order. The Ohio Companies responded to the
        applications for rehearing on February 13, 2006. In an Entry on Rehearing
        issued by the PUCO on March 1, 2006, all motions for rehearing were denied.
        Certain of these parties have subsequently filed their notices of appeal
        with
        the Supreme Court of Ohio alleging various errors made by the PUCO in its
        order
        approving the RCP. The Ohio Companies’ Motion to Intervene in the appeals was
        granted by the Supreme Court on June 8, 2006. The Appellant’s Merit Briefs were
        filed at the Supreme Court on July 5, 2006. The Appellees include the PUCO
        and
        the Ohio Companies. The Appellees’ Merit Briefs are due on August 4, 2006.
        Appellent’s Reply Briefs will then be due in August 24, 2006.
  On
        December 30,
        2004, TE filed with the PUCO two applications related to the recovery of
        transmission and ancillary service related costs. The first application sought
        recovery of these costs beginning January 1, 2006. TE requested that these
        costs be recovered through a rider that would be effective on January 1,
        2006 and adjusted each July 1 thereafter. The parties reached a settlement
        agreement that was approved by the PUCO on August 31, 2005. The incremental
        transmission and ancillary service revenues recovered from January 1 through
        June 30, 2006 were approximately $6.5 million. That amount included
        the recovery of a portion of the 2005 deferred MISO expenses as described
        below.
        On May 1, 2006, TE filed a modification to the rider to determine revenues
        ($19 million) 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. On
        January 20,
        2006, the OCC sought rehearing of the PUCO approval of the recovery of deferred
        costs through the rider during the period January 1, 2006 through
        June 30, 2006. The PUCO denied the OCC's application on February 6,
        2006. On March 23, 2006, the OCC appealed the PUCO's order to the Ohio
        Supreme Court. On March 27, 2006, the OCC filed a motion to consolidate
        this appeal with the deferral appeals discussed above and to postpone oral
        arguments in the deferral appeal until after all briefs are filed in this
        most
        recent appeal of the rider recovery mechanism. On
        March 20, 2006,
        the Ohio Supreme Court, on its own motion, consolidated the OCC's appeal
        of the
        Ohio Companies' case with a similar case involving Dayton Power & Light
        Company. Oral arguments were heard on May 10, 2006. The Ohio Companies are
        unable to predict when a decision may be issued.
 
 On
        November 1, 2005, FES filed two power sales agreements for approval with
        the FERC. One power sales agreement provided for FES to provide the PLR
        requirements of the Ohio Companies at a price equal to the retail generation
        rates approved by the PUCO for a period of three years beginning January 1,
        2006. The Ohio Companies will be relieved of their obligation to obtain PLR
        power requirements from FES if the Ohio CBP results in a lower price for
        retail
        customers.
  115
  On
        December 29, 2005, the FERC issued an order setting the two power sales
        agreements for hearing. The order criticized the Ohio CBP, and required FES
        to
        submit additional evidence in support of the reasonableness of the prices
        charged in the power sales agreements. A pre-hearing conference was held
        on
        January 18, 2006 to determine the hearing schedule in this case. Under
        upon the procedural schedule, approved in the case, FES expected an initial
        decision to be issued inin late January 2007. However, on July 14, 2006,
        the
        Chief Judge granted the joint motion of FES and the Trial Staff to appoint
        a
        settlement judge in this proceeding. The procedural schedule has been suspended
        pending negotiations among the parties.
  See Note 11 to the consolidated financial statements for further details
        and a complete discussion of regulatory matters in Ohio.
 
 *Environmental
        Matters*
 
 TE accrues environmental liabilities only when it concludes that it is
        probable that it has an obligation for such costs and can reasonably estimate
        the amount of such costs. Unasserted claims are reflected in TE’s determination
        of environmental liabilities and are accrued in the period that they are
        both
        probable and reasonably estimable.
 
 *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
        June 30, 2006, based on estimates of the total costs of cleanup, TE’s
        proportionate responsibility for such costs and the financial ability of
        other
        unaffiliated entities to pay. Included in Other Noncurrent Liabilities are
        accrued liabilities aggregating approximately $0.2 million as of
        June 30, 2006.
  See
        Note 10(B) to the consolidated financial statements for further details and
        a complete discussion of environmental matters.
 
 *Other
        Legal
        Proceedings*
  There
        are various lawsuits, claims (including claims for asbestos exposure) and
        proceedings related to TE’s normal business operations pending against TE. The
        other potentially material items not otherwise discussed above are described
        below.
 
 *Power
        Outages
        and Related Litigation-*
  On
        August 14, 2003, various states and parts of southern Canada experienced
        widespread power outages. The outages affected approximately 1.4 million
        customers in FirstEnergy's service area. The U.S. - Canada Power System Outage
        Task Force’s final report in April 2004 on the outages concluded, among other
        things, that the problems leading to the outages began in FirstEnergy’s Ohio
        service area. Specifically,
        the
        final report concluded, among other things, that the initiation of the
        August 14, 2003 power outages resulted from an alleged failure of both
        FirstEnergy and ECAR to assess and understand perceived inadequacies within
        the
        FirstEnergy system; inadequate situational awareness of the developing
        conditions; and a perceived failure to adequately manage tree growth in certain
        transmission rights of way. The Task Force also concluded that there was
        a
        failure of the interconnected grid's reliability organizations (MISO and
        PJM) to
        provide effective real-time diagnostic support. The final report is publicly
        available through the Department of Energy’s Web site (www.doe.gov). FirstEnergy
        believes that the final report does not provide a complete and comprehensive
        picture of the conditions that contributed to the August 14, 2003 power
        outages and that it does not adequately address the underlying causes of
        the
        outages. FirstEnergy remains convinced that the outages cannot be explained
        by
        events on any one utility's system. The final report contained 46
“recommendations to prevent or minimize the scope of future blackouts.”
Forty-five of those recommendations related to broad industry or policy matters
        while one, including subparts, related to activities the Task Force recommended
        be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct
        the
        causes of the August 14, 2003 power outages. FirstEnergy implemented
        several initiatives, both prior to and since the August 14, 2003 power
        outages, which were independently verified by NERC as complete in 2004 and
        were
        consistent with these and other recommendations and collectively enhance
        the
        reliability of its electric system. FirstEnergy’s implementation of these
        recommendations in 2004 included completion of the Task Force recommendations
        that were directed toward FirstEnergy. FirstEnergy is also proceeding with
        the
        implementation of the recommendations that were to be completed subsequent
        to
        2004 and will continue to periodically assess the FERC-ordered Reliability
        Study
        recommendations for forecasted 2009 system conditions, recognizing revised
        load
        forecasts and other changing system conditions which may impact the
        recommendations. Thus far, implementation of the recommendations has not
        required, nor is expected to require, substantial investment in new or material
        upgrades to existing equipment. The FERC or other applicable government agencies
        and reliability coordinators may, however, take a different view as to
        recommended enhancements or may recommend additional enhancements in the
        future
        as the result of adoption of mandatory reliability standards pursuant to
        the
        EPACT that could require additional material expenditures.
  116
  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. Three other pending PUCO complaint cases were filed by various
        insurance carriers either in their own name as subrogees or in the name of
        their
        insured. In each of these three cases, the carrier seeks reimbursement from
        various FirstEnergy companies (and, in one case, from PJM, MISO and American
        Electric Power Company, Inc., as well) for claims paid to insureds for damages
        allegedly arising as a result of the loss of power on August 14, 2003. The
        listed insureds in these cases, in many instances, are not customers of any
        FirstEnergy company. The sixth case involves the claim of a non-customer
        seeking
        reimbursement for losses incurred when its store was burglarized on
        August 14, 2003. FirstEnergy filed a Motion to Dismiss on June 13, 2006. It
        is currently expected that this case will be summarily dismissed, although
        the
        Motion is still pending. 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 as a defendant; ruled that
        the
        U.S.-Canada Power System Outage Task Force Report was not admissible into
        evidence; and gave the plaintiffs additional time to amend their complaints
        to
        otherwise comply with the PUCO’s underlying order. Also, most
        complainants, along with the FirstEnergy companies, filed applications for
        rehearing with the PUCO over various rulings contained in the March 7, 2006
        order. On April 26, 2006, the PUCO granted rehearing to allow the insurance
        company claimants, as insurers, to prosecute their claims in their name so
        long
        as they also identify the underlying insured entities and the Ohio utilities
        that provide their service. The PUCO denied all other motions for rehearing.
        The
        plaintiffs in each case have since filed an amended complaint and the named
        FirstEnergy companies have answered and also have filed a motion to dismiss
        each
        action. These motions are pending. Additionally, on June 23, 2006, one of
        the
        insurance carrier complainants filed an appeal with the Ohio Supreme Court
        over
        the PUCO’s denial of their motion for rehearing on the issue of the
        admissibility of the Task Force Report and the dismissal of FirstEnergy Corp.
        as
        a respondent. Briefing is expected to be completed on this appeal by
        mid-September. It is unknown when the Supreme Court will rule on the appeal.
        No
        estimate of potential liability is available for any of these cases.
  FirstEnergy
        is vigorously defending these actions, but cannot predict the outcome of
        any of
        these proceedings or whether any further regulatory proceedings or legal
        actions
        may be initiated against the Companies. Although unable to predict the impact
        of
        these proceedings, if FirstEnergy or its subsidiaries were ultimately determined
        to have legal liability in connection with these proceedings, it could have
        a
        material adverse effect on FirstEnergy's or its subsidiaries' financial
        condition, results of operations and cash flows.
 
 *Other
        Legal
        Matters*
  On
        October 20, 2004, FirstEnergy was notified by the SEC that the previously
        disclosed informal inquiry initiated by the SEC's Division of Enforcement
        in
        September 2003 relating to the restatements in August 2003 of previously
        reported results by FirstEnergy and the Ohio Companies, and the Davis-Besse
        extended outage, have become the subject of a formal order of investigation.
        The
        SEC's formal order of investigation also encompasses issues raised during
        the
        SEC's examination of FirstEnergy and the Companies under the now repealed
        PUHCA.
        Concurrent with this notification, FirstEnergy received a subpoena asking
        for
        background documents and documents related to the restatements and Davis-Besse
        issues. On December 30, 2004, FirstEnergy received a subpoena asking for
        documents relating to issues raised during the SEC's PUHCA examination. On
        August 24, 2005, additional information was requested regarding Davis-Besse
        related disclosures, which FirstEnergy has provided. FirstEnergy has cooperated
        fully with the informal inquiry and will continue to do so with the formal
        investigation.
  The
        City of Huron filed a complaint against OE with the PUCO challenging the
        ability
        of electric distribution utilities to collect transition charges from a customer
        of a newly-formed municipal electric utility. The complaint was filed on
        May 28, 2003, and OE timely filed its response on June 30, 2003. In a
        related filing, the Ohio Companies filed for approval with the PUCO of a
        tariff
        that would specifically allow the collection of transition charges from
        customers of municipal electric utilities formed after 1998. Both filings
        were
        consolidated for hearing and decision described above. An adverse ruling
        could
        negatively affect full recovery of transition charges by the utility. Hearings
        on the matter were held in August 2005. Initial briefs from all parties were
        filed on September 22, 2005 and reply briefs were filed on October 14,
        2005. On May 10, 2006, the PUCO issued its Opinion and Order dismissing the
        City’s complaint and approving the related tariffs, thus affirming OE’s
        entitlement to recovery of its transition charges. The City of Huron filed
        an
        application for rehearing of the PUCO’s decision on June 9, 2006 and OE
        filed a memorandum in opposition to that application on June 19, 2006. The
        PUCO denied the City’s application for rehearing on June 28, 2006. The City of
        Huron has 60 days from the denial of rehearing to appeal the PUCO’s
        decision.
  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  material adverse effect on FirstEnergy's or its
        subsidiaries' financial condition, results of operations and cash
        flows.
  117
  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**
 
 *FIN
        48 -
“Accounting for Uncertainty in Income Taxes - an interpretation of FASB
        Statement No. 109.”*
 
 In June 2006, the FASB issued FIN 48 which clarifies the accounting for
        uncertainty in income taxes recognized in an enterprise’s financial statements
        in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” This
        interpretation prescribes a recognition threshold and measurement attribute
        for
        the financial statement recognition and measurement of a tax position taken
        or
        expected to be taken on a tax return. This interpretation also provides guidance
        on derecognition, classification, interest, penalties, accounting in interim
        periods, disclosure and transition. The evaluation of a tax position in
        accordance with this interpretation will be a two-step process. The first
        step
        will determine if it is more likely than not that a tax position will be
        sustained upon examination and should therefore be recognized. The second
        step
        will measure a tax position that meets the more likely than not recognition
        threshold to determine the amount of benefit to recognize in the financial
        statements. This interpretation is effective for fiscal years beginning after
        December 15, 2006. TE is currently evaluating the impact of this
        Statement.
  118
  **PENNSYLVANIA
                    POWER COMPANY****CONSOLIDATED
                    STATEMENTS OF INCOME****(Unaudited)****Three
                    Months Ended**
                
                **Six
                    Months Ended****June
                    30,**
                
                **June
                    30,****2006**
                
                **2005**
                
                **2006**
                
                **2005****STATEMENTS
                    OF INCOME**
                ***(In
                    thousands)*****REVENUES**
                $
                80,650
                
                $
                134,282
                
                $
                163,369
                
                $
                268,766**EXPENSES:**Fuel
                
                -
                
                
                5,526
                
                
                -
                
                
                11,146Purchased
                    power
                
                56,513
                
                
                42,726
                
                
                111,269
                
                
                89,706Nuclear
                    operating costs
                
                -
                
                
                19,765
                
                
                -
                
                
                39,713Other
                    operating costs
                
                14,124
                
                
                16,743
                
                
                28,328
                
                
                29,511Provision
                    for
                    depreciation
                
                1,695
                
                
                3,810
                
                
                4,126
                
                
                7,504Amortization
                    of regulatory assets
                
                -
                
                
                9,833
                
                
                3,411
                
                
                19,715General
                    taxes
                
                5,670
                
                
                6,444
                
                
                11,504
                
                
                12,916Total
                    expenses
                
                78,002
                
                
                104,847
                
                
                158,638
                
                
                210,211**OPERATING
                    INCOME**
                
                2,648
                
                
                29,435
                
                
                4,731
                
                
                58,555**OTHER
                    INCOME (EXPENSE):**Miscellaneous
                    income
                
                3,388
                
                
                924
                
                
                6,851
                
                
                (223
                )Interest
                    expense
                
                (1,407
                )
                
                (2,787
                )
                
                (5,362
                )
                
                (5,106
                )Capitalized
                    interest
                
                48
                
                
                1,476
                
                
                82
                
                
                2,843Total
                    other
                    income (expense)
                
                2,029
                
                
                (387
                )
                
                1,571
                
                
                (2,486
                )**INCOME
                    TAXES**
                
                1,928
                
                
                13,337
                
                
                2,807
                
                
                25,356**NET
                    INCOME**
                
                2,749
                
                
                15,711
                
                
                3,495
                
                
                30,713**PREFERRED
                    STOCK DIVIDEND REQUIREMENTS**
                
                155
                
                
                738
                
                
                311
                
                
                1,378**EARNINGS
                    ON COMMON STOCK**
                $
                2,594
                
                $
                14,973
                
                $
                3,184
                
                $
                29,335The
                    preceding
                    Notes to Consolidated Financial Statements as they relate to
                    Pennsylvania
                    Power Company are an integral part
                    of these
                    statements.
   119
  **PENNSYLVANIA
                      POWER COMPANY****CONSOLIDATED
                      BALANCE SHEETS****(Unaudited)****June
                      30,**
                  
                  **December
                      31,****2006**
                  
                  **2005*****(In
                      thousands)*****ASSETS****CURRENT
                      ASSETS:**Cash
                      and cash
                      equivalents
                  $
                  38
                  
                  $
                  24Receivables
                      -Customers
                      (less accumulated provisions of $1,073,000 and $1,087,000,respectively,
                      for uncollectible accounts)
                  
                  38,303
                  
                  
                  44,555Associated
                      companies
                  
                  81,688
                  
                  
                  115,441Other
                  
                  1,332
                  
                  
                  2,889Notes
                      receivable from associated companies
                  
                  1,838
                  
                  
                  1,699Prepayments
                      and other
                  
                  17,728
                  
                  
                  86,995140,927
                  
                  
                  251,603**UTILITY
                      PLANT:**In
                      service
                  
                  365,959
                  
                  
                  359,069Less
                      -
                      Accumulated provision for depreciation
                  
                  131,181
                  
                  
                  129,118234,778
                  
                  
                  229,951Construction
                      work in progress-
                  
                  5,457
                  
                  
                  3,775240,235
                  
                  
                  233,726**OTHER
                      PROPERTY AND INVESTMENTS:**Long-term
                      notes receivable from associated companies
                  
                  276,052
                  
                  
                  283,248Other
                  
                  350
                  
                  
                  351276,402
                  
                  
                  283,599**DEFERRED
                      CHARGES AND OTHER ASSETS:**Prepaid
                      pension costs
                  
                  43,056
                  
                  
                  42,243Other
                  
                  1,775
                  
                  
                  3,82944,831
                  
                  
                  46,072$
                  702,395
                  
                  $
                  815,000**LIABILITIES
                      AND CAPITALIZATION****CURRENT
                      LIABILITIES:**Currently
                      payable long-term debt
                  $
                  15,474
                  
                  $
                  69,524Short-term
                      borrowings -Associated
                      companies
                  
                  2,161
                  
                  
                  12,703Other
                  
                  19,000
                  
                  
                  -Accounts
                      payable -Associated
                      companies
                  
                  20,420
                  
                  
                  73,444Other
                  
                  2,073
                  
                  
                  1,828Accrued
                      taxes
                  
                  23,029
                  
                  
                  28,632Accrued
                      interest
                  
                  1,070
                  
                  
                  1,877Other
                  
                  6,874
                  
                  
                  8,08690,101
                  
                  
                  196,094**CAPITALIZATION:**Common
                      stockholder's equityCommon
                      stock,
                      $30 par value, authorized 6,500,000 shares-6,290,000
                      shares outstanding
                  
                  188,700
                  
                  
                  188,700Other
                      paid in
                      capital
                  
                  71,136
                  
                  
                  71,136Retained
                      earnings
                  
                  40,281
                  
                  
                  37,097Total
                      common
                      stockholder's equity
                  
                  300,117
                  
                  
                  296,933Preferred
                      stock
                  
                  14,105
                  
                  
                  14,105Long-term
                      debt
                      and other long-term obligations
                  
                  123,343
                  
                  
                  130,677437,565
                  
                  
                  441,715**NONCURRENT
                      LIABILITIES:**Accumulated
                      deferred income taxes
                  
                  63,698
                  
                  
                  66,576Retirement
                      benefits
                  
                  46,845
                  
                  
                  45,967Regulatory
                      liabilities
                  
                  58,822
                  
                  
                  58,637Other
                  
                  5,364
                  
                  
                  6,011174,729
                  
                  
                  177,191**COMMITMENTS
                      AND CONTINGENCIES (Note 10)**$
                  702,395
                  
                  $
                  815,000The
                      preceding
                      Notes to Consolidated Financial Statements as they relate to
                      Pennsylvania
                      Power Company are an integral part
                      of these
                      balance sheets.
   120
  **PENNSYLVANIA
                      POWER COMPANY****CONSOLIDATED
                      STATEMENTS OF CASH FLOWS****(Unaudited)****Six
                      Months Ended****June
                      30,****2006**
                  
                  
                  **2005*****(In
                      thousands)*****CASH
                      FLOWS FROM OPERATING ACTIVITIES:**Net
                      income
                  
                  $
                  3,495
                  
                  $
                  30,713Adjustments
                      to
                      reconcile net income to net cash from operating activities
                      -Provision
                      for
                      depreciation
                  
                  
                  4,126
                  
                  
                  7,504Amortization
                      of regulatory assets
                  
                  
                  3,411
                  
                  
                  19,715Nuclear
                      fuel
                      and other amortization
                  
                  
                  -
                  
                  
                  8,278Deferred
                      income taxes and investment tax credits, net
                  
                  
                  (2,383
                  )
                  
                  (4,955
                  )Decrease
                      (increase) in operating assets -Receivables
                  
                  
                  41,562
                  
                  
                  10,838Materials
                      and
                      supplies
                  
                  
                  -
                  
                  
                  (806
                  )Prepayments
                      and other current assets
                  
                  
                  69,267
                  
                  
                  (8,260
                  )Increase
                      (decrease) in operating liabilities -Accounts
                      payable
                  
                  
                  (52,779
                  )
                  
                  (19,895
                  )Accrued
                      taxes
                  
                  
                  (5,602
                  )
                  
                  12,103Accrued
                      interest
                  
                  
                  (807
                  )
                  
                  116Other
                  
                  
                  (3,290
                  )
                  
                  463Net
                      cash
                      provided from operating activities
                  
                  
                  57,000
                  
                  
                  55,814**CASH
                      FLOWS FROM FINANCING ACTIVITIES:**New
                      Financing
                      -Short-term
                      borrowings, net
                  
                  
                  8,458
                  
                  
                  33,745Redemptions
                      and Repayments -Preferred
                      stock
                  
                  
                  -
                  
                  
                  (37,750
                  )Long-term
                      debt
                  
                  
                  (61,899
                  )
                  
                  (810
                  )Short-term
                      borrowings, net
                  
                  
                  -
                  
                  
                  -Dividend
                      Payments -Common
                      stock
                  
                  
                  -
                  
                  
                  (8,000
                  )Preferred
                      stock
                  
                  
                  (311
                  )
                  
                  (1,378
                  )Net
                      cash used
                      for financing activities
                  
                  
                  (53,752
                  )
                  
                  (14,193
                  )**CASH
                      FLOWS FROM INVESTING ACTIVITIES:**Property
                      additions
                  
                  
                  (10,216
                  )
                  
                  (41,093
                  )Proceeds
                      from
                      nuclear decommissioning trust fund sales
                  
                  
                  -
                  
                  
                  36,995Investments
                      in
                      nuclear decommissioning trust funds
                  
                  
                  -
                  
                  
                  (37,792
                  )Loan
                      repayments from associated companies
                  
                  
                  7,057
                  
                  
                  173Other
                  
                  
                  (75
                  )
                  
                  82Net
                      cash used
                      for investing activities
                  
                  
                  (3,234
                  )
                  
                  (41,635
                  )Net
                      increase
                      (decrease) in cash and cash equivalents
                  
                  
                  14
                  
                  
                  (14
                  )Cash
                      and cash
                      equivalents at beginning of period
                  
                  
                  24
                  
                  
                  38Cash
                      and cash
                      equivalents at end of period
                  
                  $
                  38
                  
                  $
                  24The
                      preceding
                      Notes to Consolidated Financial Statements as they relate to
                      Pennsylvania
                      Power Company are an integral part
                      of these
                      statements.
 
 121
  
 
 ***Report
        of Independent Registered Public Accounting Firm***
 
 
 
 
 
 
 
 
 
 To
        the Stockholder
        and Board of
 Directors
        of
        Pennsylvania Power Company:
 
 We
        have reviewed the
        accompanying consolidated balance sheet of Pennsylvania Power Company and
        its
        subsidiaries as of June 30, 2006, and the related consolidated statement
        of
        income for each of the three-month and six-month periods ended June 30,
        2006 and 2005 and the consolidated statement of cash flows for the six-month
        period ended June 30, 2006 and 2005. These interim financial statements are
        the
        responsibility of the Company’s management.
 
 We
        conducted our
        review in accordance with the standards of the Public Company Accounting
        Oversight Board (United States). A review of interim financial information
        consists principally of applying analytical procedures and making inquiries
        of
        persons responsible for financial and accounting matters. It is substantially
        less in scope than an audit conducted in accordance with the standards of
        the
        Public Company Accounting Oversight Board, the objective of which is the
        expression of an opinion regarding the financial statements taken as a whole.
        Accordingly, we do not express such an opinion.
 
 Based
        on our review,
        we are not aware of any material modifications that should be made to the
        accompanying consolidated interim financial statements for them to be in
        conformity with accounting principles generally accepted in the United States
        of
        America.
 
 We
        have previously
        audited, in accordance with the standards of the Public Company Accounting
        Oversight Board (United States), the consolidated balance sheet as of December
        31, 2005, and the related consolidated statements of income, capitalization,
        common stockholder’s equity, preferred stock, cash flows and taxes for the year
        then ended (not presented herein), and in our report [which contained references
        to the Company’s change in its method of accounting for asset retirement
        obligations as of January 1, 2003 as discussed in Note 2(G) and Note 8 to
        those
        consolidated financial statements] dated February 27, 2006, we expressed
        an
        unqualified opinion on those consolidated financial statements. In our opinion,
        the information set forth in the accompanying consolidated balance sheet
        as of
        December 31, 2005, is fairly stated in all material respects in relation
        to the
        consolidated balance sheet from which it has been derived.
 
 
 
 
 PricewaterhouseCoopers
        LLP
 Cleveland,
        Ohio
 August
        4,
        2006
 
 
  122
  **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**
  In 2005, Penn and 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 comparative earnings results with reductions in
        both revenues and expenses. Revenues are reduced due to the termination of
        certain arrangements with FES, under which Penn previously sold its
        nuclear-generated KWH to FES and leased its non-nuclear generation assets
        to
        FGCO, a subsidiary of FES. Penn’s expenses are lower due to the nuclear fuel and
        operating costs assumed by NGC as well as depreciation and property tax expenses
        assumed by FGCO and NGC related to the transferred generating assets. In
        addition, Penn receives interest income on associated company notes receivable
        from the transfer of its generation net assets. FES will continue to provide
        Penn’s PLR requirements under revised purchased power arrangements during 2006
        (see Outlook -- Regulatory Matters).
  123
  The effects on Penn’s results of operations in the second quarter and first six
        months of 2006 compared to the same periods of 2005 from the generation asset
        transfers are summarized in the following table:
 
 **Intra-System
                  Generation Asset Transfers****Income
                  Statement Effects**
              
              **Three
                  Months**
              
              
              **Six
                  Months****Increase
                  (Decrease)**
              
              ***(In
                  millions)***Revenues:Non-nuclear
                  generating units rent
              (a)
              $
              (5
              )
              
              $
              (10
              )Nuclear
                  generated KWH sales
              (b)
              
              (38
              )
              
              
              (76
              )Total
                  -
                  Revenues Effect
              
              
              (43
              )
              
              
              (86
              )Expenses:Fuel
                  costs -
                  nuclear
              (c)
              
              (5
              )
              
              
              (11
              )Nuclear
                  operating costs
              (c)
              
              (20
              )
              
              
              (40
              )Provision
                  for
                  depreciation
              (d)
              
              (1
              )
              
              
              (3
              )General
                  taxes
              (e)
              
              (1
              )
              
              
              (1
              )Total
                  -
                  Expenses Effect
              
              
              (27
              )
              
              
              (54
              )Operating
                  Income Effect
              
              
              (16
              )
              
              
              (32
              )Other
                  Income:Interest
                  income from notes receivable
              (f)
              
              2
              
              
              
              5
              )Capitalized
                  Interest
              (g)
              
              (1
              )
              
              
              (3
              )Total
                  - Other
                  Income Effect
              
              
              1
              
              
              
              2Income
                  taxes
              (h)
              
              (6
              )
              
              
              (12
              )Net
                  Income
                  Effect
              
              $
              (9
              )
              
              $
              (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
                  to generation assets.(e)
                  Reduction
                  of property tax expense on generation assets.(f)
                  Interest
                  income on associated company notes receivable from the transfer
                  of
                  generation net assets.(g)
                  Reduction
                  of allowance for borrowed funds used during construction on nuclear
                  capital expenditures.(h)
                  Income tax
                  effect of the above adjustments.
 
 **Results
        of Operations**
 
 Earnings on common stock in the second quarter of 2006 decreased to $2.6
        million
        from $15 million in the second quarter of 2005. During the first six months
        of 2006 earnings on common stock decreased to $3.2 million from $29 million
        in
        the first six months of 2005. The lower earnings resulted principally from
        the
        generation asset transfer effects shown in the table above.
 
 *Revenues*
 
 Revenues decreased by $54 million, or 40%, and $105 million,
        or 39%, in the second quarter of 2006 and the first six months of 2006,
        respectively, as compared with the same period of 2005, primarily due to
        the
        generation asset transfer impact displayed in the table above. Excluding
        the
        effects of the asset transfer, revenues decreased by $11 million, or 12%
        and $19
        million, or 11%, in the second quarter and the first six months of 2006,
        respectively. The decreases in the second quarter and the first half of 2006
        resulted from lower distribution revenues ($9 million and $18 million,
        respectively) primarily reflecting the completion of Penn's generation-related
        transition cost recovery under Penn’s rate restructuring plan, and lower
        wholesale revenues ($6 million and $12 million, respectively) resulting from
        the
        termination of a wholesale sales agreement with a non-affiliate in December
        2005. These decreases were partially offset by an increase in retail generation
        revenues of $5 million in the second quarter of 2006 and $11 million in the
        first six months of 2006, primarily from higher composite unit prices associated
        with a 5% rate increase for generation permitted by the PPUC for all customer
        classes - total retail generation KWH sales remained substantially
        unchanged.
 
 Lower distribution KWH deliveries to residential and commercial
        customers in the second quarter and first six months of 2006 reflect the
        impact
        of milder weather conditions compared to the same periods of 2005. Higher
        KWH
        deliveries to industrial customers in both periods of 2006 are largely due
        to
        increased demand from the steel sector.
  124
  
 Changes in distribution deliveries in the second quarter and the first six
        months of 2006 from the same periods of 2005 are summarized in the following
        table:
 
 **Changes
                  in Distribution Deliveries**
              
              **Three
                  Months**
              
              **Six
                  Months****Increase
                  (Decrease)**Distribution
                  Deliveries:Residential
              
              
              (7.8)
              %
              
              (4.9)
              %Commercial
              
              
              (4.1)
              %
              
              (2.7)
              %Industrial
              
              
              10.3
              %
              
              7.2
              %**Total
                  Distribution Deliveries**
              
              
              **-**
              %
              
              **(0.04)**
              **%**
 
 *Expenses*
 
 Total
        expenses
        decreased by $27 million in the second quarter and $52 million in the first
        six
        months of 2006 from the same periods of 2005 principally due to the generation
        asset transfer impact as shown previously. Excluding the asset transfer effects,
        the following presents changes from the prior year by expense
        category:
 
 **Expenses
                  - Changes**
              
              **Three
                  Months**
              
              **Six
                  Months*****(In
                  millions)*****Increase
                  (Decrease)**Purchased
                  power costs
              
              $
              14
              
              $
              21Other
                  operating costs
              
              
              (3
              )
              
              (1
              )Provision
                  for
                  depreciation
              
              
              (1
              )
              
              -Amortization
                  of regulatory assets
              
              
              (10
              )
              
              (16
              )General
                  Taxes
              
              
              -
              
              
              (1
              )**Net
                  change in expenses**
              
              **$**
              **-**
              
              **$**
              **3**
 
 I ncreased
        purchased
        power costs in the second quarter and the first six months of 2006, compared
        with the same periods of 2005, resulted from higher unit prices associated
        with
        a new power supply agreement with FES, partially offset by decreases in KWH
        purchased due to lower generation sales requirements. Other operating costs
        decreased primarily due to lower employee benefit costs and a decrease in
        the
        use of outside contractors for tree trimming *.* The
        provision for
        depreciation included an immaterial pretax adjustment of $0.7 million ($0.4
        million net of tax) applicable to prior periods.
 
 Amortization
        of
        regulatory assets was lower in the second quarter and the first six months
        of
        2006 as compared to the same periods of 2005 due to the completion of Penn's
        rate restructuring plan and related transition cost amortization.
 
 *Other
        Income
        (Expense)*
 
 Investment
        income
        increased $2 million in the second quarter and $7 million the first
        six months of 2006, compared with the same periods of 2005, primarily due
        to the
        impact of the generation asset transfer.
 
 *Net
        Interest
        Charges*
 
 Net
        interest charges
        were substantially unchanged in the second quarter and increased $3 million
        in
        the first six months as compared to the same periods of 2005 primarily due
        to
        the reduction of capitalized interest related to the generation asset
        transfer.
 
 **Capital
        Resources and Liquidity**
 
 Penn’s
        cash
        requirements in 2006 for 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.
  125
  
 *Changes
        in Cash
        Position*
 
 Penn
        had $38,000 of
        cash and cash equivalents as of June 30, 2006 compared with $24,000 as of
        December 31, 2005. The major sources for changes in these balances are
        summarized below.
 
 *Cash
        Flows From
        Operating Activities*
 
 Net
        cash provided
        from operating activities in the first six months of 2006, compared with
        the
        corresponding 2005 period, was as follows:
 
 **Six
                  Months Ended****June
                  30,****Operating
                  Cash Flows**
              
              **2006**
              
              **2005*****(in
                  millions)***Cash
                  earnings(*)
              
              $
              9
              
              $
              62Working
                  capital and other
              
              
              48
              
              
              (6
              )Net
                  cash
                  provided from operating activities
              
              $
              57
              
              $
              56(*)Cash earnings
                  are a non-GAAP measure (see reconciliation
                  below).
 
 Cash
        earnings (in
        the table above) are not a measure of performance calculated in accordance
        with
        GAAP. Penn believes that cash earnings 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:
   **Six
                    Months Ended**
                  **June
                    30,****Reconciliation
                    of Cash Earnings**
                
                **2006**
                
                **2005*****(In
                    millions)***Net
                    income
                    (GAAP)
                
                $
                3
                
                $
                31Non-cash
                    charges (credits):Provision
                    for
                    depreciation
                
                
                4
                
                
                8Amortization
                    of regulatory assets
                
                
                3
                
                
                20Nuclear
                    fuel
                    and other amortization
                
                
                -
                
                
                8Deferred
                    income taxes and investment tax credits, net
                
                
                (2
                )
                
                (5
                )Other
                    non-cash
                    Items
                
                
                1
                
                
                -Cash
                    earnings
                    (Non-GAAP)
                
                $
                9
                
                $
                62
 The
        $53 million
        decrease in cash earnings for the first six months of 2006, as compared to
        the
        corresponding period of 2005, is described above under “Results of Operations”,
        and resulted principally from the impact of the generation asset transfer.
        The
        $54 million change in working capital was primarily due to increases in
        cash provided from the settlement of receivables of $31 million and a
        $78 million change in prepayments and other current assets, principally as
        a result of the asset transfer discussed above. These variances were partially
        offset by increased cash outflows from the settlement of accounts payable
        of
        $33 million and an $18 million change in accrued taxes.
 
 *Cash
        Flows From
        Financing Activities*
 
 Net
        cash used for
        financing activities totaled $54 million in the first six months of 2006,
        compared with $14 million in the same period of 2005. The $40 million
        increase resulted from $62 million of long-term debt redemptions in 2006
        principally related to the generation asset transfer discussed above and
        a $25
        million decrease in short-term borrowings, partially offset by decreases
        of $38
        million in preferred stock redemptions and reductions of $8 million in common
        stock dividend payments to OE as compared to the first six months of 2005.
 
 Penn
        had $2 million
        of cash and temporary investments (which included short-term notes receivable
        from associated companies) and $21 million of short-term indebtedness as
        of
        June 30, 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 $44 million (including the utility money pool). Penn
        had the capability to issue $66 million of additional FMB on the basis of
        property additions and retired bonds as of June 30, 2006. Based upon
        applicable earnings coverage tests, Penn could issue up to $290 million of
        preferred stock (assuming no additional debt was issued) as of June 30,
        2006.
  126
  
 Short-term
        borrowings outstanding as of June 30, 2006, consisted of $19 million of
        borrowings from affiliates. Penn Power Funding LLC (Penn Funding), a wholly
        owned subsidiary of Penn, is a limited liability company whose borrowings
        are
        secured by customer accounts receivable purchased from Penn. Penn Funding
        can
        borrow up to $25 million under a receivables financing arrangement at rates
        based on bank commercial paper rates. The financing arrangements require
        payment
        of an annual facility fee of 0.125% on the entire finance limit. Penn Funding’s
        receivables financing agreements expire June 28, 2007. As a separate legal
        entity with separate creditors, it would have to satisfy its separate
        obligations to creditors before any of its remaining assets could be made
        available to Penn .
 
 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 LOC’s expiring up to one
        year from the date of issuance. The stated amount of outstanding LOC’s 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 June 30, 2006.
 
 The
        revolving credit
        facility contains financial covenants requiring each borrower to maintain
        a
        consolidated debt to total capitalization ratio of no more than 65%. As of
        June
        30, 2006, Penn's debt to total capitalization as defined under the revolving
        credit facility was 34%.
 
 The
        facility does
        not contain any provisions that either restrict Penn's ability to borrow
        or
        accelerate repayment of outstanding advances as a result of any change in
        its
        credit ratings. Pricing is defined in “pricing grids”, whereby the cost of funds
        borrowed under the facility is related to Penn's credit ratings.
 
 Penn
        has the ability
        to borrow from its regulated affiliates and FirstEnergy to meet its short-term
        working capital requirements. FESC administers this money pool and tracks
        surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving
        a loan under the money pool agreements must repay the principal amount, together
        with accrued interest, within 364 days of borrowing the funds. The rate of
        interest is the same for each company receiving a loan from the pool and
        is
based on the average cost of funds available through the pool. The average
        interest rate for borrowings under these arrangements in the first six months
        of
        2006 was 4.86%.
 
 Penn's
        access to the
        capital markets and the costs of financing are influenced by the ratings
        of its
        securities and the securities of OE and FirstEnergy. The rating outlook from
        S&P on all securities is stable. Moody's and Fitch's ratings outlook on all
        securities is positive.
  In the first six months of 2006, pollution control notes that were formerly
        obligations of Penn were refinanced and became obligations of FGCO and NGC.
        The
        proceeds from the refinancings were used to repay a portion of their associated
        company notes payable to Penn. With those repayments, Penn redeemed pollution
        control notes in the principal amount of $16.8 million at 5.9%, $12.7 million
        at
        6.15%, $14.25 million at 6%, $10.3 million at 3.61%, and $6.95 million at
        5.45%.
 
 *Cash
        Flows From
        Investing Activities*
 
 Net
        cash used for
        investing activities totaled $3 million in the first six months of 2006,
        compared with $42 million in the same period of 2005. The $39 million
        decrease in the 2006 period reflects a $31 million reduction in property
        additions, principally as a result of the generation asset transfer discussed
        above and a $7 million increase in loan repayments from associated
        companies.
 
 During
        the last half
        of 2006, capital requirements for property additions are expected to be
        approximately $8 million. Penn has sinking fund requirements of
        approximately $0.5 million for maturing long-term debt during the remainder
        of 2006. These cash requirements are expected to be satisfied from internal
        cash
        and short-term credit arrangements.
 
 Penn’s
        capital
        spending for the period 2006-2010 is expected to be approximately $90 million
        of
        which approximately $18 million applies to 2006. Penn had no other material
        obligations as of June 30, 2006 that have not been recognized on its
        Consolidated Balance Sheet.
  127
  
 **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 $59 million as of June
        30, 2006 and December 31, 2005, and are included under Noncurrent
        Liabilities on the Consolidated Balance Sheets.
 
 Under Pennsylvania's electric competition law, Penn is required to secure
        generation supply for customers who do not choose alternative suppliers for
        their electricity. On October 11, 2005, Penn filed a plan with the PPUC to
        secure electricity supply for its customers at set rates following the end
        of
        its transition period on December 31, 2006. Penn recommended that the RFP
        process cover the period January 1, 2007 through May 31, 2008. To the
        extent that an affiliate of Penn supplies a portion of the PLR load included
        in
        the RFP, authorization to make the affiliate sale must be obtained from the
        FERC. Hearings before the PPUC were held on January 10, 2006 with main
        briefs filed on January 27, 2006 and reply briefs filed on February 3,
        2006. On February 16, 2006, the ALJ issued a Recommended Decision to adopt
        Penn's RFP process with modifications. On April 20, 2006, the PPUC approved
        the
        Recommended Decision with additional modifications to use an RFP process
        to
        obtain Penn's power supply requirements after 2006 through two separate
        solicitations. An initial solicitation was held for Penn in May 2006 with
        all
        tranches fully subscribed. On June 2, 2006, the PPUC approved the bid results
        for the first solicitation. On July 18, 2006, the second PLR solicitation
        was
        held for Penn. The tranches for the Residential Group and Small Commercial
        Group
        were fully subscribed. However, supply was only acquired for three of the
        five
        tranches for the Large Commercial Group. On July 20, 2006, the PPUC approved
        the
        submissions for the second bid. A residual solicitation is scheduled to be
        held
        on August 15, 2006 for the two remaining Large Commercial Group tranches.
        Acceptance of the winning bids is subject to approval by the PPUC.
 On
          November 1, 2005, FES filed a power sales agreement for approval with the
          FERC that would permit Penn to obtain its PLR power requirements from FES
          at a
          fixed price equal to the retail generation price during 2006. As discussed
          above, subsequent to the PPUC’s approval of Penn's plan for the RFP process to
          obtain its post 2006 power supply requirements, the customer power supply
          requirements for all of the residential and the small commercial sectors
          and the
          majority of the large commercial sector tranches have been fully subscribed
          and
          the bids approved by the PPUC. An additional solicitation for the remaining
          two
          large commercial sector tranches is scheduled for August 15, 2006.
 On
        May 25,
        2006, Penn filed a Petition for Review of the PPUC’s Orders of April 28,
        2006 and May 4, 2006, which together decided the issues associated with
        Penn’s proposed Interim PLR Supply Plan. Penn has asked the Commonwealth Court
        to review the PPUC’s decision to deny its recovery of certain PLR costs via a
        reconciliation mechanism and its decision to impose a geographic limitation
        on
        the sources of alternative energy credits. On June 7, 2006, the PaDEP filed
        a Petition for Review appealing the PPUC’s ruling on the method by which
        alternative energy credits may be acquired and traded. Penn is unable to
        predict
        the outcome of this appeal.
 
 See
        Note 11 to
        the consolidated financial statements for further details and a complete
        discussion of regulatory matters in Pennsylvania.
 
 ***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.
  128
  
 *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.
        Those requirements will be the responsibility of FGCO. The settlement agreement
        also requires OE and Penn to spend up to $25 million toward environmentally
        beneficial projects, which include wind energy purchased power agreements
        over a
        20-year term. OE and Penn agreed to pay a civil penalty of $8.5 million.
        Results for the first quarter of 2005 included the penalties paid by OE and
        Penn
        of $7.8 million and $0.7 million, respectively. OE and Penn also
        recognized liabilities in the first quarter of 2005 of $9.2 million and
        $0.8 million, respectively, for probable future cash contributions toward
        environmentally beneficial projects.
  ***Other
        Legal Proceedings***
 
 There are various lawsuits, claims (including claims for asbestos exposure)
        and
        proceedings related to Penn’s normal business operations pending against Penn.
        The other material items not otherwise discussed above are described
        below.
 
 *Power
        Outages
        and Related Litigation*
 
 On August 14, 2003, various states and parts of southern Canada experienced
        widespread power outages. The outages affected approximately 1.4 million
        customers in FirstEnergy's service area. The U.S. - Canada Power System Outage
        Task Force’s final report in April 2004 on the outages concluded, among other
        things, that the problems leading to the outages began in FirstEnergy’s Ohio
        service area. Specifically,
        the
        final report concluded, among other things, that the initiation of the
        August 14, 2003 power outages resulted from an alleged failure of both
        FirstEnergy and ECAR to assess and understand perceived inadequacies within
        the
        FirstEnergy system; inadequate situational awareness of the developing
        conditions; and a perceived failure to adequately manage tree growth in certain
        transmission rights of way. The Task Force also concluded that there was
        a
        failure of the interconnected grid's reliability organizations (MISO and
        PJM) to
        provide effective real-time diagnostic support. The final report is publicly
        available through the Department of Energy’s Web site (www.doe.gov). FirstEnergy
        believes that the final report does not provide a complete and comprehensive
        picture of the conditions that contributed to the August 14, 2003 power
        outages and that it does not adequately address the underlying causes of
        the
        outages. FirstEnergy remains convinced that the outages cannot be explained
        by
        events on any one utility's system. The final report contained 46
“recommendations to prevent or minimize the scope of future blackouts.”
Forty-five of those recommendations related to broad industry or policy matters
        while one, including subparts, related to activities the Task Force recommended
        be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct
        the
        causes of the August 14, 2003 power outages. FirstEnergy implemented
        several initiatives, both prior to and since the August 14, 2003 power
        outages, which were independently verified by NERC as complete in 2004 and
        were
        consistent with these and other recommendations and collectively enhance
        the
        reliability of its electric system. FirstEnergy’s implementation of these
        recommendations in 2004 included completion of the Task Force recommendations
        that were directed toward FirstEnergy. FirstEnergy is also proceeding with
        the
        implementation of the recommendations that were to be completed subsequent
        to
        2004 and will continue to periodically assess the FERC-ordered Reliability
        Study
        recommendations for forecasted 2009 system conditions, recognizing revised
        load
        forecasts and other changing system conditions which may impact the
        recommendations. Thus far, implementation of the recommendations has not
        required, nor is expected to require, substantial investment in new or material
        upgrades to existing equipment. The FERC or other applicable government agencies
        and reliability coordinators may, however, take a different view as to
        recommended enhancements or may recommend additional enhancements in the
        future
        as the result of adoption of mandatory reliability standards pursuant to
        the
        EPACT that could require additional material expenditures.
 
 FirstEnergy
        is vigorously defending these actions, but cannot predict the outcome of
        any of
        these proceedings or whether any further regulatory proceedings or legal
        actions
        may be initiated against the Companies. Although unable to predict the impact
        of
        these proceedings, if FirstEnergy or its subsidiaries were ultimately determined
        to have legal liability in connection with these proceedings, it could have
        a
        material adverse effect on FirstEnergy's or its subsidiaries' financial
        condition, results of operations and cash flows.
  129
   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**
 
 *FIN
        48 -
“Accounting for Uncertainty in Income Taxes - an interpretation of FASB
        Statement No. 109.”*
 
 In
        June 2006, the
        FASB issued FIN 48 which clarifies the accounting for uncertainty in income
        taxes recognized in an enterprise’s financial statements in accordance with FASB
        Statement No. 109, “Accounting for Income Taxes.” This interpretation prescribes
        a recognition threshold and measurement attribute for the financial statement
        recognition and measurement of a tax position taken or expected to be taken
        on a
        tax return. This interpretation also provides guidance on derecognition,
        classification, interest, penalties, accounting in interim periods, disclosure
        and transition. The evaluation of a tax position in accordance with this
        interpretation will be a two-step process. The first step will determine
        if it
        is more likely than not that a tax position will be sustained upon examination
        and should therefore be recognized. The second step will measure a tax position
        that meets the more likely than not recognition threshold to determine the
        amount of benefit to recognize in the financial statements. This interpretation
        is effective for fiscal years beginning after December 15, 2006. Penn is
        currently evaluating the impact of this Statement.
  130
 **JERSEY
                        CENTRAL POWER & LIGHT
                        COMPANY****CONSOLIDATED
                        STATEMENTS OF INCOME AND COMPREHENSIVE
                        INCOME****(Unaudited)****Three
                        Months Ended**
                    
                    **Six
                        Months Ended****June
                        30,**
                    
                    **June
                        30,****2006**
                    
                    **2005**
                    
                    **2006**
                    
                    **2005****Restated**
                    
                    
                    
                    **Restated****STATEMENTS
                        OF INCOME**
                    
                    ***(In
                        thousands)*****REVENUES**
                    
                    $
                    611,484
                    
                    $
                    595,291
                    
                    $
                    1,187,276
                    
                    $
                    1,124,383**EXPENSES**Purchased
                        power
                    
                    
                    343,045
                    
                    
                    321,393
                    
                    
                    658,755
                    
                    
                    598,525Other
                        operating costs
                    
                    
                    72,105
                    
                    
                    80,239
                    
                    
                    155,133
                    
                    
                    181,306Provision
                        for
                        depreciation
                    
                    
                    20,826
                    
                    
                    19,856
                    
                    
                    41,454
                    
                    
                    40,062Amortization
                        of regulatory assets
                    
                    
                    65,526
                    
                    
                    70,250
                    
                    
                    132,271
                    
                    
                    138,624Deferral
                        of
                        new regulatory assets
                    
                    
                    -
                    
                    
                    (27,765
                    )
                    
                    -
                    
                    
                    (27,765
                    )General
                        taxes
                    
                    
                    14,272
                    
                    
                    14,824
                    
                    
                    30,504
                    
                    
                    30,264Total
                        expenses
                    
                    
                    515,774
                    
                    
                    478,797
                    
                    
                    1,018,117
                    
                    
                    961,016**OPERATING
                        INCOME**
                    
                    
                    95,710
                    
                    
                    116,494
                    
                    
                    169,159
                    
                    
                    163,367**OTHER
                        INCOME (EXPENSE):**Miscellaneous
                        income
                    
                    
                    2,528
                    
                    
                    201
                    
                    
                    6,071
                    
                    
                    487Interest
                        Expense
                    
                    
                    (20,367
                    )
                    
                    (20,100
                    )
                    
                    (40,983
                    )
                    
                    (41,003
                    )Capitalized
                        interest
                    
                    
                    1,037
                    
                    
                    437
                    
                    
                    1,929
                    
                    
                    840Total
                        other
                        income (expense)
                    
                    
                    (16,802
                    )
                    
                    (19,462
                    )
                    
                    (32,983
                    )
                    
                    (39,676
                    )**INCOME
                        TAXES**
                    
                    
                    38,632
                    
                    
                    42,729
                    
                    
                    62,190
                    
                    
                    55,939**NET
                        INCOME**
                    
                    
                    40,276
                    
                    
                    54,303
                    
                    
                    73,986
                    
                    
                    67,752**PREFERRED
                        STOCK DIVIDEND REQUIREMENTS**
                    
                    
                    125
                    
                    
                    125
                    
                    
                    250
                    
                    
                    250**EARNINGS
                        ON COMMON STOCK**
                    
                    $
                    40,151
                    
                    $
                    54,178
                    
                    $
                    73,736
                    
                    $
                    67,502**STATEMENTS
                        OF COMPREHENSIVE INCOME****NET
                        INCOME**
                    
                    $
                    40,276
                    
                    $
                    54,303
                    
                    $
                    73,986
                    
                    $
                    67,752**OTHER
                        COMPREHENSIVE INCOME:**Unrealized
                        gain on derivative hedges
                    
                    
                    38
                    
                    
                    36
                    
                    
                    107
                    
                    
                    105Income
                        tax
                        expense related to other comprehensive income
                    
                    
                    15
                    
                    
                    15
                    
                    
                    43
                    
                    
                    43Other
                        comprehensive income, net of tax
                    
                    
                    23
                    
                    
                    21
                    
                    
                    64
                    
                    
                    62**TOTAL
                        COMPREHENSIVE INCOME**
                    
                    $
                    40,299
                    
                    $
                    54,324
                    
                    $
                    74,050
                    
                    $
                    67,814The
                        preceding
                        Notes to Consolidated Financial Statements as they relate
                        to Jersey
                        Central Power & Light Company are an integral part
                        of these
                        statements.
   131
  **JERSEY
                        CENTRAL POWER & LIGHT COMPANY****CONSOLIDATED
                        BALANCE SHEETS****(Unaudited)****June
                        30,**
                    
                    **December
                        31,****2006**
                    
                    **2005*****(In
                        thousands)*****ASSETS****CURRENT
                        ASSETS:**Cash
                        and cash
                        equivalents
                    
                    $
                    95
                    
                    $
                    102Receivables-Customers
                        (less accumulated provisions of $3,078,000 and $3,830,000,respectively,
                        for uncollectible accounts)
                    
                    
                    282,352
                    
                    
                    258,077Associated
                        companies
                    
                    
                    142
                    
                    
                    203Other
                        (less
                        accumulated provisions of $206,000 and $204,000,respectively,
                        for uncollectible accounts)
                    
                    
                    41,317
                    
                    
                    41,456Notes
                        receivable - associated companies
                    
                    
                    27,766
                    
                    
                    18,419Materials
                        and
                        supplies, at average cost
                    
                    
                    2,012
                    
                    
                    2,104Prepayments
                        (sales & use, corp. business, TEFA) taxes
                    
                    
                    110,787
                    
                    
                    10,137Prepayments
                        and other
                    
                    
                    5,210
                    
                    
                    6,928469,681
                    
                    
                    337,426**UTILITY
                        PLANT:**In
                        service
                    
                    
                    3,983,859
                    
                    
                    3,902,684Less
                        -
                        Accumulated provision for depreciation
                    
                    
                    1,454,291
                    
                    
                    1,445,7182,529,568
                    
                    
                    2,456,966Construction
                        work in progress
                    
                    
                    77,325
                    
                    
                    98,7202,606,893
                    
                    
                    2,555,686**OTHER
                        PROPERTY AND INVESTMENTS:**Nuclear
                        fuel
                        disposal trust
                    
                    
                    165,132
                    
                    
                    164,203Nuclear
                        plant
                        decommissioning trusts
                    
                    
                    149,000
                    
                    
                    145,975Other
                    
                    
                    2,069
                    
                    
                    2,580316,201
                    
                    
                    312,758**DEFERRED
                        CHARGES AND OTHER ASSETS:**Regulatory
                        assets
                    
                    
                    2,121,811
                    
                    
                    2,226,591Goodwill
                    
                    
                    1,978,141
                    
                    
                    1,985,858Prepaid
                        pension costs
                    
                    
                    150,760
                    
                    
                    148,054Other
                    
                    
                    16,410
                    
                    
                    17,7334,267,122
                    
                    
                    4,378,236$
                    7,659,897
                    
                    $
                    7,584,106**LIABILITIES
                        AND CAPITALIZATION****CURRENT
                        LIABILITIES:**Currently
                        payable long-term debt
                    
                    $
                    57,586
                    
                    $
                    207,231Notes
                        payable-Associated
                        companies
                    
                    
                    365,164
                    
                    
                    181,346Accounts
                        payable-Associated
                        companies
                    
                    
                    16,425
                    
                    
                    37,955Other
                    
                    
                    194,619
                    
                    
                    149,501Accrued
                        taxes
                    
                    
                    45,295
                    
                    
                    54,356Accrued
                        interest
                    
                    
                    20,278
                    
                    
                    19,916Cash
                        collateral from suppliers
                    
                    
                    32,434
                    
                    
                    141,225Other
                    
                    
                    78,214
                    
                    
                    86,884810,015
                    
                    
                    878,414**CAPITALIZATION:**Common
                        stockholder's equity-Common
                        stock,
                        $10 par value, authorized 16,000,000 shares-15,371,270
                        shares outstanding
                    
                    
                    153,713
                    
                    
                    153,713Other
                        paid-in
                        capital
                    
                    
                    2,995,542
                    
                    
                    3,003,190Accumulated
                        other comprehensive loss
                    
                    
                    (1,966
                    )
                    
                    (2,030
                    )Retained
                        earnings
                    
                    
                    104,626
                    
                    
                    55,890Total
                        common
                        stockholder's equity
                    
                    
                    3,251,915
                    
                    
                    3,210,763Preferred
                        stock
                    
                    
                    12,649
                    
                    
                    12,649Long-term
                        debt
                        and other long-term obligations
                    
                    
                    1,162,407
                    
                    
                    972,0614,426,971
                    
                    
                    4,195,473**NONCURRENT
                        LIABILITIES:**Power
                        purchase
                        contract loss liability
                    
                    
                    1,122,933
                    
                    
                    1,237,249Accumulated
                        deferred income taxes
                    
                    
                    827,760
                    
                    
                    812,034Nuclear
                        fuel
                        disposal costs
                    
                    
                    179,039
                    
                    
                    175,156Asset
                        retirement obligation
                    
                    
                    81,949
                    
                    
                    79,527Retirement
                        benefits
                    
                    
                    72,520
                    
                    
                    72,454Other
                    
                    
                    138,710
                    
                    
                    133,7992,422,911
                    
                    
                    2,510,219**COMMITMENTS
                        AND CONTINGENCIES (Note 10)**$
                    7,659,897
                    
                    $
                    7,584,106The
                        preceding
                        Notes to Consolidated Financial Statements as they relate
                        to Jersey
                        Central Power & Light Company are an integral part of these balance
                        sheets.
   132
  **JERSEY
                        CENTRAL POWER & LIGHT COMPANY****CONSOLIDATED
                        STATEMENTS OF CASH FLOWS****(Unaudited)****Six
                        Months Ended****June
                        30,****2006**
                    
                    **2005****Restated*****(In
                        thousands)*****CASH
                        FLOWS FROM OPERATING ACTIVITIES:**Net
                        income
                    
                    $
                    73,986
                    
                    $
                    67,752Adjustments
                        to
                        reconcile net income to net cash from operating activities
                        -Provision
                        for
                        depreciation
                    
                    
                    41,454
                    
                    
                    40,062Amortization
                        of regulatory assets
                    
                    
                    132,271
                    
                    
                    138,624Deferral
                        of
                        new regulatory assets
                    
                    
                    -
                    
                    
                    (27,765
                    )Deferred
                        purchased power and other costs
                    
                    
                    (134,759
                    )
                    
                    (126,265
                    )Deferred
                        income taxes and investment tax credits, net
                    
                    
                    10,942
                    
                    
                    16,426Accrued
                        compensation and retirement benefits
                    
                    
                    (3,436
                    )
                    
                    (8,029
                    )Cash
                        collateral from (returned to) suppliers
                    
                    
                    (108,791
                    )
                    
                    198Decrease
                        (increase) in operating assets -Receivables
                    
                    
                    (24,074
                    )
                    
                    14,271Materials
                        and
                        supplies
                    
                    
                    91
                    
                    
                    177Prepayments
                        and other current assets
                    
                    
                    (98,932
                    )
                    
                    (66,525
                    )Increase
                        (decrease) in operating liabilities -Accounts
                        payable
                    
                    
                    23,589
                    
                    
                    32,087Accrued
                        taxes
                    
                    
                    (9,062
                    )
                    
                    58,139Accrued
                        interest
                    
                    
                    362
                    
                    
                    580Other
                    
                    
                    (1,642
                    )
                    
                    16,856Net
                        cash
                        provided from (used for) operating activities
                    
                    
                    (98,001
                    )
                    
                    156,588**CASH
                        FLOWS FROM FINANCING ACTIVITIES:**New
                        Financing-Long-term
                        debt
                    
                    
                    200,003
                    
                    
                    -Short-term
                        borrowings, net
                    
                    
                    183,818
                    
                    
                    30,572Redemptions
                        and Repayments-Long-term
                        debt
                    
                    
                    (157,659
                    )
                    
                    (63,327
                    )Dividend
                        Payments-Common
                        stock
                    
                    
                    (25,000
                    )
                    
                    (40,000
                    )Preferred
                        stock
                    
                    
                    (250
                    )
                    
                    (250
                    )Net
                        cash
                        provided from (used for) financing activities
                    
                    
                    200,912
                    
                    
                    (73,005
                    )**CASH
                        FLOWS FROM INVESTING ACTIVITIES:**Property
                        additions
                    
                    
                    (91,101
                    )
                    
                    (82,661
                    )Loan
                        repayments from (loans to) associated companies, net
                    
                    
                    (9,347
                    )
                    
                    670Proceeds
                        from
                        nuclear decommissioning trust fund sales
                    
                    
                    109,505
                    
                    
                    53,782Investments
                        in
                        nuclear decommissioning trust funds
                    
                    
                    (110,952
                    )
                    
                    (55,229
                    )Other
                    
                    
                    (1,023
                    )
                    
                    105Net
                        cash used
                        for investing activities
                    
                    
                    (102,918
                    )
                    
                    (83,333
                    )Net
                        increase
                        (decrease) in cash and cash equivalents
                    
                    
                    (7
                    )
                    
                    250Cash
                        and cash
                        equivalents at beginning of period
                    
                    
                    102
                    
                    
                    162Cash
                        and cash
                        equivalents at end of period
                    
                    $
                    95
                    
                    $
                    412The
                        preceding
                        Notes to Consolidated Financial Statements as they relate
                        to Jersey
                        Central Power & Light Company are
                        an
                        integral part of these
                        statements.
   133
    ***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 June 30, 2006, and the related consolidated
          statements of income and comprehensive income for each of the three-month
          and
          six-month periods ended June 30, 2006 and 2005 and the consolidated statement
          of
          cash flows for the six-month period ended June 30, 2006 and 2005. These
          interim
          financial statements are the responsibility of the Company’s
          management.
 
 We
          conducted our
          review in accordance with the standards of the Public Company Accounting
          Oversight Board (United States). A review of interim financial information
          consists principally of applying analytical procedures and making inquiries
          of
          persons responsible for financial and accounting matters. It is substantially
          less in scope than an audit conducted in accordance with the standards
          of the
          Public Company Accounting Oversight Board, the objective of which is the
          expression of an opinion regarding the financial statements taken as a
          whole.
          Accordingly, we do not express such an opinion.
 
 Based
          on our review,
          we are not aware of any material modifications that should be made to the
          accompanying consolidated interim financial statements for them to be in
          conformity with accounting principles generally accepted in the United
          States of
          America.
 
 We
          have previously
          audited, in accordance with the standards of the Public Company Accounting
          Oversight Board (United States), the consolidated balance sheet as of December
          31, 2005, and the related consolidated statements of income, capitalization,
          common stockholder’s equity, preferred stock, cash flows and taxes for the year
          then ended (not presented herein), and in our report [which contained references
          to the Company’s restatement of its previously issued consolidated financial
          statements for the years ended December 31, 2004 and 2003 as discussed
          in Note
          2(I) to those consolidated financial statements] dated February 27, 2006,
          we
          expressed an unqualified opinion on those consolidated financial statements.
          In
          our opinion, the information set forth in the accompanying consolidated
          balance
          sheet as of December 31, 2005, is fairly stated in all material respects
          in
          relation to the consolidated balance sheet from which it has been
          derived.
 
 
 
 
 PricewaterhouseCoopers
          LLP
 Cleveland,
          Ohio
 August
          4,
          2006
 
 
  134
  **JERSEY
          CENTRAL POWER & LIGHT COMPANY**
 
 **MANAGEMENT’S
          DISCUSSION AND** **ANALYSIS
          OF**
 **RESULTS
          OF
          OPERATIONS** **** **AND
          FINANCIAL CONDITION**
 
 
 JCP&L
          is a
          wholly owned, electric utility subsidiary of FirstEnergy. JCP&L conducts
          business in New Jersey, providing regulated electric transmission and
          distribution services. JCP&L also provides generation services to those
          customers electing to retain JCP&L as their power supplier.
 
 **Restatements**
  As further discussed in Note 15 to the Consolidated Financial Statements,
          JCP&L restated its consolidated financial statements for the three months
          and six months ended June 30, 2005. The revisions are the result of a tax
          audit
          from the State of New Jersey, in which JCP&L became aware that the New
          Jersey Transitional Energy Facilities Assessment is not an allowable deduction
          for state income tax purposes .
 
 **Results
          of Operations**
 
 Earnings
          on common
          stock in the second quarter of 2006 decreased to $40.2 million from
          $54.2 million in 2005. The decrease was principally due to the absence of
          the deferral of a new regulatory asset in 2005 and increased purchased
          power
          costs, partially offset by increased revenues and decreased other operating
          costs. In the first six months of 2006, earnings on common stock increased
          to
          $73.7 million compared to $67.5 million for the same period in 2005. The
          increase was primarily due to higher revenues and lower other operating
          costs
          partially offset by increased purchased power costs and the absence of
          the
          regulatory asset deferred in 2005.
 
 *Revenues*
 
 Revenues
          increased
          $16.2 million or 2.7% in the second quarter of 2006 and $62.9 million or
          5.6%
          for the first six months of 2006 compared with the same periods of 2005.
          The
          higher revenues in both periods were primarily due to retail generation
          revenue
          increases ($28.5 million and $66.3 million in the second quarter and the
          first
          six months of 2006, respectively), partially offset by wholesale revenue
          decreases ($7.6 million in the second quarter and $5.8 million in the first
          six
          months of 2006). Distribution revenues declined $1.1 million in the second
          quarter of 2006 but increased $4.2 million in the first six months of 2006
          compared to the same periods of the prior year.
 
 The
          retail
          generation revenue increases in both the second quarter and the first six
          months
          of 2006 as compared to the previous year were due to higher unit prices
          resulting from the BGS auctions effective in May 2006 and May 2005, which
          partially offset declines in retail generation KWH sales. Revenue from
          residential customers increased $12.7 million and $27.6 million in the
          second
          quarter and the first six months of 2006, respectively, as compared to
          the same
          periods in 2005. Generation revenue from commercial customers also increased
          for
          the same periods by $15.3 million and $36.3 million, respectively. The
          milder
          weather in the second quarter and the first six months of 2006 as compared
          to
          the previous year (cooling degree days were 3.5% below the previous year
          and
          heating degree days were 18.6% below the previous year) resulted in lower
          KWH
          sales to residential customers in the second quarter and the first six
          months of
          2006. The milder weather also resulted in overall lower KWH sales to commercial
          customers in the second quarter and first six months of 2006 - more than
          offsetting the impact of commercial customers returning to JCP&L from
          alternative suppliers. Revenues from industrial customers increased $0.3
          million
          and $2.1 million in the second quarter and first six months of 2006,
          respectively, as compared to the previous year, as a result of higher unit
          prices offsetting KWH sales decreases in the second quarter and the first
          six
          months of 2006. Wholesale sales revenues decreased $7.6 million in the
          second quarter and $5.8 million for the first six months of 2006 as compared
          to
          2005 as lower unit prices offset KWH sales increases.
 
 The
          decrease in
          distribution revenues of $1.1 million in the second quarter of 2006 compared
          to
          the same period of 2005 consists of two components, a $1.8 million increase
          in
          wires revenue and a $2.9 million reduction in MTC and SBC revenues. The
          distribution revenue reduction was primarily due to lower KWH throughput
          partially offset by higher composite unit prices resulting from a distribution
          rate increase pursuant to the stipulated settlements approved by the NJBPU
          on
          May 25, 2005. While distribution KWH deliveries declined for the first six
          months of 2006 as compared to the previous year, the impact of a full six
          months
          of 2006 of the distribution rate increase caused revenues to increase $4.2
          million. Wires revenue increased $13.3 million while the MTC and SBC revenues
          declined $9.1 million. Other revenues declined $3.6 million in the second
          quarter and $1.8 million in the first six months of 2006 as compared to
          the
          comparable periods in 2005 due to reduced transmission
          revenues.
  135
  
 Changes
          in KWH sales
          by customer class in the second quarter and the first six months of 2006
          compared to the same periods of 2005 are summarized in the following
          table:
 
 **Three**
                
                **Six****Changes
                    in KWH Sales**
                
                **Months**
                
                **Months****Increase
                    (Decrease)**Electric
                    Generation:Retail
                
                
                (3.3)
                %
                
                (1.4)
                %Wholesale
                
                
                2.2
                %
                
                1.1
                %**Total
                    Electric Generation Sales**
                
                
                **(2.1)**
                **%**
                
                **(0.9)**
                **%**Distribution
                    Deliveries:Residential
                
                
                (5.3)
                %
                
                (4.7)
                %Commercial
                
                
                (0.3)
                %
                
                (0.7)
                %Industrial
                
                
                (6.5)
                %
                
                (6.8)
                %**Total
                    Distribution Deliveries**
                
                
                **(3.2)**
                **%**
                
                **(3.3)**
                **%**
  *Expenses*
 
 Total
          expenses and
          taxes increased by $37.1 million in the second quarter and $57.0 million
          in the
          first six months of 2006 as compared to the same periods of the prior year.
          The
          following table presents changes from the prior year by expense
          category:
 
 **Three**
                
                **Six****Expenses
                    - Changes**
                
                **Months**
                
                **Months*****(In
                    millions)*****Increase
                    (Decrease)**Purchased
                    power costs
                
                $
                21.7
                
                $
                60.2Other
                    operating costs
                
                
                (8.1
                )
                
                (26.2
                )Provision
                    for
                    depreciation
                
                
                1.0
                
                
                1.4Amortization
                    of regulatory assets
                
                
                (4.7
                )
                
                (6.4
                )Deferral
                    of
                    new regulatory assets
                
                
                27.8
                
                
                27.8General
                    Taxes
                
                
                (0.6
                )
                
                0.2**Net
                    increase in expenses**
                
                $
                37.1
                
                $
                57.0
 
 Purchased
          power
          costs increased $21.7 million in the second quarter of 2006 and $60.2 million
          in
          the first six months compared to the same periods of 2005. The increase
          reflected higher unit prices resulting from the 2006 and 2005 BGS auctions.
          The
          change in the deferral of new regulatory assets of $27.8 million in both
          periods
          was due to the absence of a 2005 deferral of reliability expenses reflecting
          a
          May 2005 NJBPU rate decision. Other operating costs declined $8.1 million
          in the
          second quarter and $26.2 million for the first six months of 2006 due in
          part to
          the absence of costs related to the JCP&L labor strike in 2005. Amortization
          of regulatory assets decreased $4.7 million in the second quarter and $6.4
          million in the first six months of 2006 due to a reduction in the level
          of MTC
          revenue recovery.
 
 Miscellaneous
          income
          increased $2.3 million in the second quarter of 2006 and $5.6 million in
          the
          first six months compared to the same periods in 2005. The increases in
          both
          periods is attributed to income received from customer requested service
          projects.
 
 **Capital
          Resources and Liquidity**
 
 JCP&L’s
          cash
          requirements in 2006 for 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 June 30,
          2006, JCP&L had $95,000 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.
  136
  
 *Cash
          Flows From
          Operating Activities*
 
 Cash
          provided from
          operating activities in the first six months of 2006 compared with the
          first six
          months of 2005 were as follows:
  **Six
                      Months Ended****June
                      30,****Operating
                      Cash Flows**
                  
                  **2006**
                  
                  **2005*****(In
                      millions)***Cash
                      earnings(1)
                  
                  $
                  120
                  
                  $
                  101Working
                      capital and other
                  
                  
                  (218
                  )
                  
                  56Net
                      cash
                      provided from operating activities
                  
                  $
                  (98
                  )
                  $
                  157(1)Cash earnings
                      are a non-GAAP measure (see reconciliation below).
  Cash earnings (in the table above) are not a measure of performance calculated
          in accordance with GAAP. JCP&L believes that cash earnings are a useful
          financial sure 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:
 
 **Six
                    Months Ended****June
                    30,****Reconciliation
                    of Cash Earnings******
                
                **2006**
                
                **2005*****(In
                    millions)***Net
                    income
                    (GAAP)
                
                $
                74
                
                $
                68Non-cash
                    charges (credits):Provision
                    for
                    depreciation
                
                
                41
                
                
                40Amortization
                    of regulatory assets
                
                
                132
                
                
                139Deferral
                    of
                    new regulatory assets
                
                
                -
                
                
                (28
                )Deferred
                    purchased power and other costs
                
                
                (135
                )
                
                (126
                )Deferred
                    income taxes
                
                
                11
                
                
                16Other
                    non-cash
                    items
                
                
                (3
                )
                
                (8
                )Cash
                    earnings
                    (Non-GAAP)
                
                $
                120
                
                $
                101
 
 The
          $19 million
          increase in cash earnings is described under “Results of Operations.” The
          $274 million decrease from working capital changes primarily resulted from
          a $109 million change in cash collateral from suppliers, changes in prepayments
          of $32 million, accrued taxes of $67 million and receivables of $38
          million. In the year 2005, JCP&L received cash collateral payments from its
          suppliers of $135 million. During the first six months of 2006, JCP&L
          returned $109 million back to its suppliers.
 
 *Cash
          Flows From
          Financing Activities*
 
 Net
          cash provided
          from financing activities was $201 million in the first six months of 2006
          as
          compared to net cash used of $73 million in same period of 2005. The change
          resulted from a $200 million issuance of long-term debt, a $153 million
          increase
          in short-term borrowings and a $15 million reduction in common stock
          dividend payments to FirstEnergy, partially offset by $94 million of
          additional debt redemptions in the first six months of 2006.
 
 JCP&L  had
          $28 million of
          cash and temporary investments (which includes short-term notes receivable
          from
          associated companies) and approximately $365 million of short-term
          indebtedness as of June 30, 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
          June 30, 2006, JCP&L had the capability to issue $610 million of
          additional senior notes based upon FMB collateral. As of June 30, 2006,
          based upon applicable earnings coverage tests and its charter, JCP&L could
          issue $1.3 billion of preferred stock (assuming no additional debt was
          issued).
 
 JCP&L
          has the
          ability to borrow from FirstEnergy and its regulated affiliates to meet
          its
          short-term working capital requirements. FESC administers this money pool
          and
          tracks surplus funds of FirstEnergy and its regulated subsidiaries. Companies
          receiving a loan under the money pool agreement must repay the principal,
          together with accrued interest, within 364 days of borrowing the funds.
          The rate
          of interest is the same for each company receiving a loan from the pool
          and is
          based on the average cost of funds available through the pool. The average
          interest rate for borrowings in the first six months of 2006 was 4.86%.
  137
  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
          June 30, 2006, JCP&L's debt to total capitalization as defined under
          the revolving credit facility was 29%.
 
 The
          facility does
          not contain any provisions that either restrict JCP&L's ability to borrow or
          accelerate repayment of outstanding advances as a result of any change
          in its
          credit ratings. Pricing is defined in “pricing grids”, whereby the cost of funds
          borrowed under the facility is related to its credit ratings.
 
 JCP&L's
          access
          to the capital markets and the costs of financing are dependent on the
          ratings
          of its securities and that of FirstEnergy. As of June 30, 2006, JCP&L's
          and FirstEnergy’s ratings outlook from S&P on all securities was stable. The
          ratings outlook from Moody’s and Fitch on all securities is
          positive.
  On June 8, 2006, the NJBPU approved JCP&L’s request to issue securitization
          bonds associated with BGS stranded cost deferrals. On August 4, 2006, JCP&L
          Transition Funding II, a wholly owned subsidiary of JCP&L, secured pricing
          on the issuance of $182 million of transition bonds with a weighted average
          interest rate of 5.5%. As required by the Electric Discount and Energy
          Competition Act of 1999, as amended. JCP&L will use the proceeds it receives
          from the issuer principally to reduce stranded costs, including basic generation
          transition costs, through the retirement of debt, including short-term
          debt, or
          equity or both, and also to pay related expenses.
 
 On
          May 12, 2006,
          JCP&L issued $200 million of 6.40% secured Senior Notes due 2036. The
          proceeds of the offering were used to repay at maturity $150 million
          aggregate principal amount of JCP&L’s 6.45% Senior Notes due May 15, 2006
          and for general corporate purposes.
 
 *Cash
          Flows From
          Investing Activities*
 
 Net
          cash used for
          investing activities was $103 million in the first six months of 2006
          compared to $83 million in the previous year. The $20 million change
          primarily resulted from increases of $8 million in property additions for
          distribution system reliability initiatives and $9 million of loans to
          associated companies.
 
 During
          the last half
          of
          2006, capital requirements for property additions and improvements are
          expected
          to be about $72 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 approximately
          $912 million for property additions, of which approximately $162 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.
  138
  *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 changes in the fair value of commodity
          derivative contracts related to energy production during the second quarter
          and
          first six months of 2006 are summarized in the following table:
 
 **Three
                    Months Ended**
                
                **Six
                    Months Ended****Increase
                    (Decrease) in the Fair Value**
                
                **June
                    30, 2006**
                
                **June
                    30, 2006****of
                    Commodity Derivative Contracts**
                
                **Non-Hedge**
                
                **Hedge**
                
                **Total**
                
                **Non-Hedge**
                
                **Hedge**
                
                **Total*****(In
                    millions)*****Change
                    in the Fair Value of****Commodity
                    Derivative Contracts:**Outstanding
                    net liability at beginning of period
                
                $
                (1,173
                )
                $
                -
                
                $
                (1,173
                )
                $
                (1,223
                )
                $
                -
                
                $
                (1,223
                )New
                    contract
                    value when entered
                
                
                -
                
                
                -
                
                
                -
                
                
                -
                
                
                -
                
                
                -Additions/change
                    in value of existing contracts
                
                
                (15
                )
                
                -
                
                
                (15
                )
                
                (30
                )
                
                -
                
                
                (30
                )Change
                    in
                    techniques/assumptions
                
                
                -
                
                
                -
                
                
                -
                
                
                -
                
                
                -
                
                
                -Settled
                    contracts
                
                
                76
                
                
                -
                
                
                76
                
                
                141
                
                
                -
                
                
                141**Net
                    Liabilities - Derivative Contracts**
                  **at
                    End
                    of Period****(1)**
                
                $
                (1,112
                )
                $
                -
                
                $
                (1,112
                )
                $
                (1,112
                )
                $
                -
                
                $
                (1,112
                )**Impact
                    of Changes in Commodity Derivative Contracts****(2)**Income
                    Statement effects (pre-tax)
                
                $
                (1
                )
                $
                -
                
                $
                (1
                )
                $
                (1
                )
                $
                -
                
                $
                (1
                )Balance
                    Sheet
                    effects:Regulatory
                    assets (net)
                
                $
                (62
                )
                $
                -
                
                $
                (62
                )
                $
                (112
                )
                $
                -
                
                $
                (112
                )
 
 (1)  Includes
          $1,112
          million of non-hedge commodity derivative contracts (primarily with NUGs),
          that
          are offset by a regulatory asset.
 (2)  Represents
          the
          change in value of existing contracts, settled contracts and changes in
          techniques/assumptions.
  Derivatives are included on the Consolidated Balance Sheet as of June 30,
          2006
          as follows:
 
 **Balance
                    Sheet Classification**
                
                **Non-Hedge**
                
                **Hedge**
                
                **Total*****(In
                    millions)*****Non-Current-**Other
                    deferred
                    charges
                
                
                11
                
                
                -
                
                
                11Other
                    noncurrent liabilities
                
                
                (1,123
                )
                
                -
                
                
                (1,123
                )**Net
                    liabilities**
                
                **$**
                **(1,112**
                **)**
                **$**
                **-**
                
                **$**
                **(1,112**
                **)**
 
 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 June 30, 2006 are summarized by year
          in the following table:
 
 **Source
                    of Information****Fair
                    Value by Contract Year**
                
                **2006**(1)
                
                **2007**
                
                **2008**
                
                **2009**
                
                **2010**
                
                **Thereafter**
                
                **Total*****(In
                    millions)***Other
                    external
                    sources(2)
                
                $
                (147)
                
                
                (257)
                
                
                (226)
                
                
                -
                
                
                -
                
                
                -
                
                
                (630)Prices
                    based
                    on models
                
                
                -
                
                
                -
                
                
                -
                
                
                (168)
                
                
                (144)
                
                
                (170)
                
                
                (482)**Total**(3)
                
                **$**
                **(147)**
                
                **$**
                **(257)**
                
                **$**
                **(226)**
                
                **$**
                **(168)**
                
                **$**
                **(144)**
                
                **$**
                **(170)**
                
                **$**
                **(1,112)**
 
 (1)  For
          the last two
          quarters of 2006.
 (2)  Broker
          quote
          sheets.
 (3)  Includes
          $1,112
          million of non-hedge commodity derivative contracts (primarily with NUGs),
          that
          are offset by a regulatory asset and does not affect earnings.
  139
 
 JCP&L performs sensitivity analyses to estimate its exposure to the market
          risk of its commodity positions. A hypothetical 10% adverse shift in quoted
          market prices in the near term on both its trading and non-trading derivative
          instruments would not have had a material effect on JCP&L’s consolidated
          financial position or cash flows as of June 30, 2006. JCP&L estimates
          that if energy commodity prices experienced an adverse 10% change, net
          income
          for the next twelve months would not change, as the prices for all commodity
          positions are already above the contract price caps.
 
 *Equity
          Price
          Risk*
 
 Included
          in nuclear
          decommissioning trusts are marketable equity securities carried at their
          current
          fair value of approximately $86 million and $84 million as of June 30,
          2006 and December 31, 2005, respectively. A hypothetical 10% decrease in
          prices quoted by stock exchanges would result in a $9 million reduction in
          fair value as of June 30, 2006.
 
 **Regulatory
          Matters**
  Regulatory assets are costs which have been authorized by the NJBPU and
          the FERC
          for recovery from customers in future periods or for which authorization
          is
          probable. Without the probability of such authorization, costs currently
          recorded as regulatory assets would have been charged to income as incurred.
          All
          of JCP&L’s regulatory assets are expected to continue to be recovered under
          the provisions of the regulatory proceedings discussed below. JCP&L’s
          regulatory assets totaled $2.1 billion as of June 30, 2006 and $2.2 billion
          as of 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 June 30, 2006, the accumulated
          deferred cost balance totaled approximately $638 million. New Jersey law
          allows
          for securitization of JCP&L's deferred balance upon application by JCP&L
          and a determination by the NJBPU that the conditions of the New Jersey
          restructuring legislation are met. On February 14, 2003, JCP&L filed for
          approval to securitize the July 31, 2003 deferred balance. On June 8, 2006,
          the
          NJBPU approved JCP&L’s request to issue securitization bonds associated with
          BGS stranded cost deferrals. On August 4, 2006, JCP&L Transition Funding II,
          a wholly owned subsidiary of JCP&L, secured pricing on the issuance of $182
          million of transition bonds with a weighted average interest rate of
          5.5%.
  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 23, 2006, JCP&L filed updated data
          reflecting actual amounts through December 31, 2005 of $154 million of
          costs incurred since July 31, 2003. On March 29, 2006, a pre-hearing
          conference was held with the presiding ALJ. 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 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 last of the quarterly reliability reports was submitted
          on June
          12, 2006. As of June 30, 2006, there were no performance penalties issued
          by the NJBPU.
  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. On June 21, 2006,
          the NJBPU approved the continued use of a descending block auction for
          the Fixed
          Price Residential Class. A final decision as to the procurement method
          for the
          Commercial Industrial Energy Price Class is expected in October
          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 its 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.
  140
  On
          August 1,
          2005, the NJBPU established a proceeding to determine whether additional
          ratepayer protections are required at the state level in light of the repeal
          of
          PUHCA pursuant to the EPACT. An NJBPU proposed rulemaking to address the
          issues
          was published in the NJ Register on December 19, 2005. The proposal would
          prevent a holding company that owns a gas or electric public utility from
          investing more than 25% of the combined assets of its utility and
          utility-related subsidiaries into businesses unrelated to the utility industry.
          A public hearing was held on February 7, 2006 and comments were submitted
          to the NJBPU. 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. With the
          approval
          of the NJBPU Staff, the affected utilities jointly submitted an alternative
          proposal on June 1, 2006. Comments on the alternative proposal were submitted
          on
          June 15, 2006. JCP&L is unable to predict the outcome of this
          proceeding.
  On December 21, 2005, the NJBPU initiated a generic proceeding and requested
          comments in order to formulate an appropriate regulatory treatment for
          investment tax credits related to generation assets divested by New Jersey’s
          four electric utility companies. Comments were filed by the utilities and
          by the
          DRA. JCP&L was advised by the IRS on April 10, 2006 that the ruling was
          tentatively adverse. On April 28, 2006, the NJBPU directed JCP&L to
          withdraw its request for a private letter ruling on this issue, which had
          been
          previously filed with the IRS as ordered by the NJBPU. On May 11, 2006,
          after a
          JCP&L Motion for Reconsideration was denied by the NJBPU, JCP&L filed to
          withdraw the request for a private letter ruling. On July 19, 2006, the
          IRS
          acknowledged that the JCP&L ruling request was withdrawn.
  On November 18, 2004, the FERC issued an order eliminating the RTOR for
          transmission service between the MISO and PJM regions. The FERC also ordered
          the
          MISO, PJM and the transmission owners within MISO and PJM to submit compliance
          filings containing a SECA mechanism to recover lost RTOR revenues during
          a
          16-month transition period from load serving entities. The FERC issued
          orders in
          2005 setting the SECA for hearing. ATSI, JCP&L, Met-Ed, Penelec, and FES
          continue to be involved in the FERC hearings concerning the calculation
          and
          imposition of the SECA charges. The hearing was held in May 2006. Initial
          briefs were submitted on June 9, 2006 and reply briefs were filed on June
          27, 2006. The 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 refund and hearing procedures. On
          June 30, 2005, the settling PJM transmission owners filed a request for
          rehearing of the May 31, 2005 order. On
          March 20, 2006, a settlement was filed with FERC in the formula rate
          proceeding that generally accepts the companies' formula rate proposal.
          The FERC
          issued an order approving this settlement on April 19, 2006. Hearings in
          the PJM rate design case concluded in April 2006. On July 13, 2006, an
          Initial
          Decision was issued by the ALJ. The ALJ adopted the Trial Staff’s position that
          the cost of all PJM transmission facilities should be recovered through
          a
          postage stamp rate. The ALJ recommended an April 1, 2006 effective date
          for this
          change in rate design. If the FERC accepts this recommendation, the transmission
          rate applicable to many load zones in PJM would increase. FirstEnergy believes
          that significant additional transmission revenues would have to be recovered
          from the JCP&L, Met-Ed and Penelec transmission zones within PJM. The
          Companies, as part of the Responsible Pricing Alliance, intend to submit
          a brief
          on exceptions within thirty days of the initial decision. Following submission
          of reply exceptions, the case is expected to be reviewed by the FERC with
          a
          decision anticipated in the fourth quarter of 2006.
  See Note 11 to the consolidated financial statements for further details
          and a complete discussion of regulatory matters in New Jersey.
 
 **Environmental
          Matters**
  JCP&L
          accrues environmental liabilities when it concludes that it is probable
          that it
          has an obligation for such costs and can reasonably determine the amount
          of such
          costs. Unasserted claims are reflected in JCP&L’s determination of
          environmental liabilities and are accrued in the period that they are both
          probable and reasonably estimable.
  141
  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 June 30, 2006, based on estimates of the
          total costs of cleanup, JCP&L’s proportionate responsibility for such costs
          and the financial ability of other unaffiliated entities to pay. In addition,
          JCP&L has accrued liabilities for environmental remediation of former
          manufactured gas plants in New Jersey; those costs are being recovered
          by
          JCP&L through a non-bypassable SBC. Total liabilities of approximately
          $54.7 million have been accrued through June 30, 2006.
 
 See
          Note 10(B)
          to the consolidated financial statements for further details and a complete
          discussion of environmental matters.
 
 **Other
          Legal Proceedings**
  There are various lawsuits, claims (including claims for asbestos exposure)
          and
          proceedings related to JCP&L's normal business operations pending against
          JCP&L. The other material items not otherwise discussed below are described
          in Note 10(C) to the consolidated financial statements.
  On August 14, 2003, various states and parts of southern Canada experienced
          widespread power outages. The outages affected approximately 1.4 million
          customers in FirstEnergy's service area. The U.S. - Canada Power System
          Outage
          Task Force’s final report in April 2004 on the outages concluded, among other
          things, that the problems leading to the outages began in FirstEnergy’s Ohio
          service area. Specifically,
          the
          final report concluded, among other things, that the initiation of the
          August 14, 2003 power outages resulted from an alleged failure of both
          FirstEnergy and ECAR to assess and understand perceived inadequacies within
          the
          FirstEnergy system; inadequate situational awareness of the developing
          conditions; and a perceived failure to adequately manage tree growth in
          certain
          transmission rights of way. The Task Force also concluded that there was
          a
          failure of the interconnected grid's reliability organizations (MISO and
          PJM) to
          provide effective real-time diagnostic support. The final report is publicly
          available through the Department of Energy’s Web site (www.doe.gov). FirstEnergy
          believes that the final report does not provide a complete and comprehensive
          picture of the conditions that contributed to the August 14, 2003 power
          outages and that it does not adequately address the underlying causes of
          the
          outages. FirstEnergy remains convinced that the outages cannot be explained
          by
          events on any one utility's system. The final report contained 46
“recommendations to prevent or minimize the scope of future blackouts.”
Forty-five of those recommendations related to broad industry or policy
          matters
          while one, including subparts, related to activities the Task Force recommended
          be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct
          the
          causes of the August 14, 2003 power outages. FirstEnergy implemented
          several initiatives, both prior to and since the August 14, 2003 power
          outages, which were independently verified by NERC as complete in 2004
          and were
          consistent with these and other recommendations and collectively enhance
          the
          reliability of its electric system. FirstEnergy’s implementation of these
          recommendations in 2004 included completion of the Task Force recommendations
          that were directed toward FirstEnergy. FirstEnergy is also proceeding with
          the
          implementation of the recommendations that were to be completed subsequent
          to
          2004 and will continue to periodically assess the FERC-ordered Reliability
          Study
          recommendations for forecasted 2009 system conditions, recognizing revised
          load
          forecasts and other changing system conditions which may impact the
          recommendations. Thus far, implementation of the recommendations has not
          required, nor is expected to require, substantial investment in new or
          material
          upgrades to existing equipment. The FERC or other applicable government
          agencies
          and reliability coordinators may, however, take a different view as to
          recommended enhancements or may recommend additional enhancements in the
          future
          as the result of adoption of mandatory reliability standards pursuant to
          the
          EPACT that could require additional material expenditures.
  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. FirstEnergy's motion to dismiss the matter was denied
          on
          June 2, 2006. FirstEnergy has since filed an appeal, which is pending. A
          responsive pleading to this matter has been filed. Also, the complaint
          has been
          amended to include an additional party. No estimate of potential liability
          has
          been undertaken in this matter.
  FirstEnergy
          was also named, along with several other entities, in a complaint in New
          Jersey
          State Court. The allegations against FirstEnergy were based, in part, on
          an
          alleged failure to protect the citizens of Jersey City from an electrical
          power
          outage. None of FirstEnergy’s subsidiaries serve customers in Jersey City. A
          responsive pleading has been filed. On April 28, 2006, the Court granted
          FirstEnergy's motion to dismiss. The plaintiff has not
          appealed.
  142
  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**
 
 *FSP
          FIN 46(R)-6
          - “Determining the Variability to Be Considered in Applying FASB interpretation
          No. 46(R)”*
 
 In
          April 2006, the
          FASB issued FSP FIN 46(R)-6 that addresses how a reporting enterprise should
          determine the variability to be considered in applying FASB interpretation
          No.
          46 (revised December 2003). FirstEnergy adopted FIN 46(R) in the first
          quarter
          of 2004, consolidating VIE’s when FirstEnergy or one of its subsidiaries is
          determined to be the VIE’s primary beneficiary. The variability that is
          considered in applying interpretation 46(R) affects the determination of
          (a)
          whether the entity is a VIE; (b) which interests are variable interests
          in the
          entity; and (c) which party, if any, is the primary beneficiary of the
          VIE. This
          FSP states that the variability to be considered shall be based on an analysis
          of the design of the entity, involving two steps:
 
 Step
                    1:
                Analyze
                    the
                    nature of the risks in the entityStep
                    2:
                Determine
                    the
                    purpose(s) for which the entity was created and determine the
                    variability
                    the entity is designed to create and pass along to its interest
                    holders.
 
 After
          determining
          the variability to consider, the reporting enterprise can determine which
          interests are designed to absorb that variability. The guidance in this
          FSP is
          applied prospectively to all entities (including newly created entities)
          with
          which that enterprise first becomes involved and to all entities previously
          required to be analyzed under interpretation 46(R) when a reconsideration
          event
          has occurred after July 1, 2006. JCP&L does not expect this Statement to
          have a material impact on its financial statements.
 
 *FIN
          48 -
“Accounting for Uncertainty in Income Taxes - an interpretation of FASB
          Statement No. 109.”*
 
 In
          June 2006, the
          FASB issued FIN 48 which clarifies the accounting for uncertainty in income
          taxes recognized in an enterprise’s financial statements in accordance with FASB
          Statement No. 109, “Accounting for Income Taxes.” This interpretation prescribes
          a recognition threshold and measurement attribute for the financial statement
          recognition and measurement of a tax position taken or expected to be taken
          on a
          tax return. This interpretation also provides guidance on derecognition,
          classification, interest, penalties, accounting in interim periods, disclosure
          and transition. The evaluation of a tax position in accordance with this
          interpretation will be a two-step process. The first step will determine
          if it
          is more likely than not that a tax position will be sustained upon examination
          and should therefore be recognized. The second step will measure a tax
          position
          that meets the more likely than not recognition threshold to determine
          the
          amount of benefit to recognize in the financial statements. This interpretation
          is effective for fiscal years beginning after December 15, 2006. JCP&L is
          currently evaluating the impact of this Statement.
 
 **SUBSEQUENT
          EVENTS**
 
 **New
          Jersey
          Law Change**
 
 On
          July 8, 2006, the
          Governor of New Jersey signed tax legislation that increased the current
          New
          Jersey Corporate Business tax by an additional 4% surtax, which increases
          the
          effective tax from 9% to 9.36%. This increase applies to JCP&L’s 2006
          through 2008 tax years and is not expected to have a material impact on
          JCP&L’s results of operations.
  143
  **METROPOLITAN
                        EDISON COMPANY****CONSOLIDATED
                        STATEMENTS OF INCOME AND COMPREHENSIVE INCOME****(Unaudited)****Three
                        Months Ended**
                    
                    **Six
                        Months Ended****June
                        30,**
                    
                    **June
                        30,****2006**
                    
                    **2005**
                    
                    **2006**
                    
                    **2005*****(In
                        thousands)*****REVENUES**
                    
                    $
                    282,219
                    
                    $
                    263,136
                    
                    $
                    593,432
                    
                    $
                    558,917**EXPENSES:**Purchased
                        power
                    
                    
                    143,070
                    
                    
                    131,670
                    
                    
                    302,957
                    
                    
                    281,763Other
                        operating costs
                    
                    
                    59,575
                    
                    
                    52,648
                    
                    
                    120,654
                    
                    
                    111,118Provision
                        for
                        depreciation
                    
                    
                    10,288
                    
                    
                    11,377
                    
                    
                    21,193
                    
                    
                    22,898Amortization
                        of regulatory assets
                    
                    
                    25,669
                    
                    
                    25,286
                    
                    
                    55,717
                    
                    
                    53,907Deferral
                        of
                        new regulatory assets
                    
                    
                    (45,581
                    )
                    
                    -
                    
                    
                    (45,581
                    )
                    
                    -General
                        taxes
                    
                    
                    18,595
                    
                    
                    17,023
                    
                    
                    39,216
                    
                    
                    36,295Total
                        expenses
                    
                    
                    211,616
                    
                    
                    238,004
                    
                    
                    494,156
                    
                    
                    505,981**OPERATING
                        INCOME**
                    
                    
                    70,603
                    
                    
                    25,132
                    
                    
                    99,276
                    
                    
                    52,936**OTHER
                        INCOME (EXPENSE):**Interest
                        income
                    
                    
                    8,964
                    
                    
                    9,442
                    
                    
                    17,714
                    
                    
                    18,469Miscellaneous
                        income
                    
                    
                    1,792
                    
                    
                    3,288
                    
                    
                    4,404
                    
                    
                    4,429Interest
                        expense
                    
                    
                    (12,071
                    )
                    
                    (11,398
                    )
                    
                    (23,255
                    )
                    
                    (22,621
                    )Capitalized
                        interest
                    
                    
                    344
                    
                    
                    73
                    
                    
                    611
                    
                    
                    251Total
                        other
                        income (expense)
                    
                    
                    (971
                    )
                    
                    1,405
                    
                    
                    (526
                    )
                    
                    528**INCOME
                        TAXES**
                    
                    
                    29,555
                    
                    
                    10,874
                    
                    
                    40,759
                    
                    
                    21,325**NET
                        INCOME**
                    
                    
                    40,077
                    
                    
                    15,663
                    
                    
                    57,991
                    
                    
                    32,139**OTHER
                        COMPREHENSIVE INCOME:**Unrealized
                        gain on derivative hedges
                    
                    
                    84
                    
                    
                    84
                    
                    
                    168
                    
                    
                    168Income
                        tax
                        expense related to other comprehensive income
                    
                    
                    35
                    
                    
                    35
                    
                    
                    70
                    
                    
                    70Other
                        comprehensive income, net of tax
                    
                    
                    49
                    
                    
                    49
                    
                    
                    98
                    
                    
                    98**TOTAL
                        COMPREHENSIVE INCOME**
                    
                    $
                    40,126
                    
                    $
                    15,712
                    
                    $
                    58,089
                    
                    $
                    32,237The
                        preceding
                        Notes to Consolidated Financial Statements as they relate
                        to Metropolitan
                        Edison Company are an integral part of these
                        statements.
   144
  **METROPOLITAN
                        EDISON COMPANY****CONSOLIDATED
                        BALANCE SHEETS****(Unaudited)****June
                        30,**
                    
                    **December
                        31,****2006**
                    
                    **2005*****(In
                        thousands)*****ASSETS****CURRENT
                        ASSETS:**Cash
                        and cash
                        equivalents
                    
                    $
                    134
                    
                    $
                    120Receivables-Customers
                        (less accumulated provisions of $4,069,000 and $4,352,000,respectively,
                        for uncollectible accounts)
                    
                    
                    128,349
                    
                    
                    129,854Associated
                        companies
                    
                    
                    1,881
                    
                    
                    37,267Other
                    
                    
                    7,489
                    
                    
                    8,780Notes
                        receivable from associated companies
                    
                    
                    31,921
                    
                    
                    27,867Prepaid
                        gross
                        receipts taxes
                    
                    
                    25,361
                    
                    
                    2,072Prepayments
                        and other
                    
                    
                    7,115
                    
                    
                    5,840202,250
                    
                    
                    211,800**UTILITY
                        PLANT:**In
                        service
                    
                    
                    1,885,164
                    
                    
                    1,856,425Less
                        -
                        Accumulated provision for depreciation
                    
                    
                    723,799
                    
                    
                    721,5661,161,365
                    
                    
                    1,134,859Construction
                        work in progress
                    
                    
                    20,737
                    
                    
                    20,4371,182,102
                    
                    
                    1,155,296**OTHER
                        PROPERTY AND INVESTMENTS:**Nuclear
                        plant
                        decommissioning trusts
                    
                    
                    243,179
                    
                    
                    234,854Other
                    
                    
                    1,367
                    
                    
                    1,453244,546
                    
                    
                    236,307**DEFERRED
                        CHARGES AND OTHER ASSETS:**Goodwill
                    
                    
                    860,485
                    
                    
                    864,438Regulatory
                        assets
                    
                    
                    358,963
                    
                    
                    309,556Prepaid
                        pension costs
                    
                    
                    92,472
                    
                    
                    89,005Other
                    
                    
                    47,673
                    
                    
                    51,2851,359,593
                    
                    
                    1,314,284$
                    2,988,491
                    
                    $
                    2,917,687**LIABILITIES
                        AND CAPITALIZATION****CURRENT
                        LIABILITIES:**Currently
                        payable long-term debt
                    
                    $
                    150,000
                    
                    $
                    100,000Short-term
                        borrowings-Associated
                        companies
                    
                    
                    72,540
                    
                    
                    140,240Other
                    
                    
                    66,000
                    
                    
                    -Accounts
                        payable-Associated
                        companies
                    
                    
                    18,134
                    
                    
                    37,220Other
                    
                    
                    52,754
                    
                    
                    27,507Accrued
                        taxes
                    
                    
                    5,866
                    
                    
                    17,911Accrued
                        interest
                    
                    
                    9,735
                    
                    
                    9,438Other
                    
                    
                    21,539
                    
                    
                    24,274396,568
                    
                    
                    356,590**CAPITALIZATION:**Common
                        stockholder's equity-Common
                        stock,
                        without par value, authorized 900,000 shares-859,000
                        shares
                        outstanding
                    
                    
                    1,283,182
                    
                    
                    1,287,093Accumulated
                        other comprehensive loss
                    
                    
                    (1,471
                    )
                    
                    (1,569
                    )Retained
                        earnings
                    
                    
                    88,566
                    
                    
                    30,575Total
                        common
                        stockholder's equity
                    
                    
                    1,370,277
                    
                    
                    1,316,099Long-term
                        debt
                        and other long-term obligations
                    
                    
                    541,948
                    
                    
                    591,8881,912,225
                    
                    
                    1,907,987**NONCURRENT
                        LIABILITIES:**Accumulated
                        deferred income taxes
                    
                    
                    369,737
                    
                    
                    344,929Accumulated
                        deferred investment tax credits
                    
                    
                    9,643
                    
                    
                    10,043Nuclear
                        fuel
                        disposal costs
                    
                    
                    40,444
                    
                    
                    39,567Asset
                        retirement obligation
                    
                    
                    146,493
                    
                    
                    142,020Retirement
                        benefits
                    
                    
                    57,118
                    
                    
                    57,809Other
                    
                    
                    56,263
                    
                    
                    58,742679,698
                    
                    
                    653,110**COMMITMENTS
                        AND CONTINGENCIES (Note 10)**$
                    2,988,491
                    
                    $
                    2,917,687The
                        preceding
                        Notes to Consolidated Financial Statements as they relate
                        to Metropolitan
                        Edison Company are an integral part of these balance
                        sheets.
 145
   **METROPOLITAN
                        EDISON COMPANY****CONSOLIDATED
                        STATEMENTS OF CASH FLOWS****(Unaudited)****Six
                        Months Ended****June
                        30,****2006**
                    
                    **2005*****(In
                        thousands)*****CASH
                        FLOWS FROM OPERATING ACTIVITIES:**Net
                        income
                    
                    $
                    57,991
                    
                    $
                    32,139Adjustments
                        to
                        reconcile net income to net cash from operating activities
                        -Provision
                        for
                        depreciation
                    
                    
                    21,193
                    
                    
                    22,898Amortization
                        of regulatory assets
                    
                    
                    55,717
                    
                    
                    53,907Deferred
                        costs
                        recoverable as regulatory assets
                    
                    
                    (50,570
                    )
                    
                    (47,798
                    )Deferral
                        of
                        new regulatory assets
                    
                    
                    (45,581
                    )
                    
                    -Deferred
                        income taxes and investment tax credits, net
                    
                    
                    22,463
                    
                    
                    (1,898
                    )Accrued
                        compensation and retirement benefits
                    
                    
                    (4,712
                    )
                    
                    (4,519
                    )Cash
                        collateral to suppliers
                    
                    
                    (2,250
                    )
                    
                    -Decrease
                        (increase) in operating assets -Receivables
                    
                    
                    38,182
                    
                    
                    110,210Prepayments
                        and other current assets
                    
                    
                    (24,564
                    )
                    
                    (21,205
                    )Increase
                        (decrease) in operating liabilities -Accounts
                        payable
                    
                    
                    6,161
                    
                    
                    (50,593
                    )Accrued
                        taxes
                    
                    
                    (12,045
                    )
                    
                    (5,184
                    )Accrued
                        interest
                    
                    
                    297
                    
                    
                    (887
                    )Other
                    
                    
                    (4,011
                    )
                    
                    1,424Net
                        cash
                        provided from operating activities
                    
                    
                    58,271
                    
                    
                    88,494**CASH
                        FLOWS FROM FINANCING ACTIVITIES:**New
                        Financing-Long-term
                        debt
                    
                    
                    -
                    
                    
                    -Short-term
                        borrowings, net
                    
                    
                    -
                    
                    
                    20,931Redemptions
                        and Repayments-Long-term
                        debt
                    
                    
                    -
                    
                    
                    (37,830
                    )Short-term
                        borrowings, net
                    
                    
                    (1,707
                    )
                    
                    -Dividend
                        Payments-Common
                        stock
                    
                    
                    -
                    
                    
                    (34,000
                    )Net
                        cash used
                        for financing activities
                    
                    
                    (1,707
                    )
                    
                    (50,899
                    )**CASH
                        FLOWS FROM INVESTING ACTIVITIES:**Property
                        additions
                    
                    
                    (47,301
                    )
                    
                    (34,395
                    )Proceeds
                        from
                        nuclear decommissioning trust fund sales
                    
                    
                    116,704
                    
                    
                    55,081Investments
                        in
                        nuclear decommissioning trust funds
                    
                    
                    (121,446
                    )
                    
                    (59,823
                    )Loan
                        repayments from (loans to) associated companies, net
                    
                    
                    (4,054
                    )
                    
                    3,339Other
                    
                    
                    (453
                    )
                    
                    (1,797
                    )Net
                        cash used
                        for investing activities
                    
                    
                    (56,550
                    )
                    
                    (37,595
                    )Net
                        change in
                        cash and cash equivalents
                    
                    
                    14
                    
                    
                    -Cash
                        and cash
                        equivalents at beginning of period
                    
                    
                    120
                    
                    
                    120Cash
                        and cash
                        equivalents at end of period
                    
                    $
                    134
                    
                    $
                    120The
                        preceding
                        Notes to Consolidated Financial Statements as they relate
                        to Metropolitan
                        Edison Company are an integral part of
                        these statements.
 
  146
    ***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 June 30, 2006, and the related consolidated statements
          of
          income and comprehensive income for each of the three-month and six-month
          periods ended June 30, 2006 and 2005 and the consolidated statement of
          cash
          flows for the six-month period ended June 30, 2006 and 2005. These interim
          financial statements are the responsibility of the Company’s
          management.
 
 We
          conducted our
          review in accordance with the standards of the Public Company Accounting
          Oversight Board (United States). A review of interim financial information
          consists principally of applying analytical procedures and making inquiries
          of
          persons responsible for financial and accounting matters. It is substantially
          less in scope than an audit conducted in accordance with the standards
          of the
          Public Company Accounting Oversight Board, the objective of which is the
          expression of an opinion regarding the financial statements taken as a
          whole.
          Accordingly, we do not express such an opinion.
 
 Based
          on our review,
          we are not aware of any material modifications that should be made to the
          accompanying consolidated interim financial statements for them to be in
          conformity with accounting principles generally accepted in the United
          States of
          America.
 
 We
          have previously
          audited, in accordance with the standards of the Public Company Accounting
          Oversight Board (United States), the consolidated balance sheet as of December
          31, 2005, and the related consolidated statements of income, capitalization,
          common stockholder’s equity, preferred stock, cash flows and taxes for the year
          then ended (not presented herein), and in our report [which contained references
          to the Company’s change in its method of accounting for asset retirement
          obligations as of January 1, 2003 and conditional asset retirement obligations
          as of December 31, 2005 as discussed in Note 2(G) and Note 9 to those
          consolidated financial statements] dated February 27, 2006, we expressed
          an
          unqualified opinion on those consolidated financial statements. In our
          opinion,
          the information set forth in the accompanying consolidated balance sheet
          as of
          December 31, 2005, is fairly stated in all material respects in relation
          to the
          consolidated balance sheet from which it has been derived.
 
 
 
 
 PricewaterhouseCoopers
          LLP
 Cleveland,
          Ohio
 August
          4,
          2006
 
 
  147
  **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
          second quarter of 2006 increased to $40 million from $16 million in the
          second
          quarter of 2005. For the first six months of 2006, net income increased
          to $58
          million from $32 million in the same period of 2005. The increase in net
          income
          for both periods reflects higher revenues and the deferral of new regulatory
          assets, partially offset by increased purchased power costs and other operating
          costs as discussed below.
 
 *Revenues*
 
 Revenues
          increased
          by $19 million, or 7.3%, in the second quarter of 2006 and $35 million,
          or 6.2%,
          in the first six months of 2006, compared with the same periods of 2005.
          Increases in both periods were primarily due to higher retail generation
          electric revenues ($15 million for the second quarter and $27 million for
          the
          first six months) which reflected higher composite unit prices in all customer
          classes. Higher KWH sales to commercial and industrial customers were partially
          offset by lower KWH sales to residential customers. Industrial KWH sales
          increased primarily due to the return of customers to Met-Ed from alternative
          suppliers. Sales by alternative suppliers as a percent of total industrial
          sales
          in Met-Ed’s franchise area decreased by 14.5 percentage points, in the second
          quarter of 2006 and 14.2 percentage points in the first six months of 2006.
          For
          both periods, residential KWH sales decreased primarily due to the milder
          weather in 2006 compared with 2005.
 
 Revenues
          from
          distribution throughput increased by $1 million in the second quarter of
          2006
          compared with the same period of 2005. The increase was due to higher composite
          unit prices and a 0.4% increase in total KWH deliveries. This relatively
          flat
          change in KWH deliveries reflected a 3.2% increase in deliveries to commercial
          customers primarily due to a 1.7% increase in the number of commercial
          customers, partially offset by milder weather in the second quarter of
          2006 (a
          21% decrease in heating degree days and an 8.0% decrease in cooling degree
          days)
          compared to the same period in 2005. The $1 million decrease in distribution
          revenues in the first six months of 2006 was primarily due to a 1.1% decrease
          in
          KWH deliveries, reflecting the milder temperatures in 2006 compared to
          the same
          period in 2005.
 
 For
          both periods,
          transmission revenues increased primarily due to higher transmission prices,
          which also resulted in higher transmission expenses as discussed below.
          In the
          first six months of 2006, other revenues also increased due to a $2 million
          increase in the first quarter of 2006, compared to the same period in 2005,
          for
          a 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 second quarter and the first six months of 2006
          compared with the same periods in 2005 are summarized in the following
          table:
 
 **Three**
                
                **Six****Changes
                    in KWH Sales**
                
                **Months**
                
                **Months****Increase
                    (Decrease)**Retail
                    Electric Generation:Residential
                
                
                (1.0
                )%
                
                (1.9
                )%Commercial
                
                
                4.2
                %
                
                2.1
                %Industrial
                
                
                15.8
                %
                
                14.0
                %**Total
                    Retail Electric Generation Sales**
                
                
                **5.6**
                **%**
                
                **3.7**
                **%**Distribution
                    Deliveries:Residential
                
                
                (1.2
                )%
                
                (2.1
                )%Commercial
                
                
                3.2
                %
                
                1.2
                %Industrial
                
                
                (0.9
                )%
                
                (2.3
                )%**Total
                    Distribution Deliveries**
                
                
                **0.4**
                **%**
                
                **(1.1**
                )%
 
  148
  *Expenses*
  Total expenses decreased by $27 million and $12 million in the second quarter
          and the first six months of 2006, respectively, compared with the same
          periods
          of 2005. The following table presents changes from the prior year by expense
          category:
 
 **Three**
                
                **Six****Expenses
                    - Changes**
                
                **Months**
                
                **Months****Increase
                    (Decrease)**
                
                ***(In
                    millions)***Purchased
                    power costs
                
                $
                11
                
                $
                21Other
                    operating costs
                
                
                7
                
                
                10Provision
                    for
                    depreciation
                
                
                (1
                )
                
                (2
                )Amortization
                    of regulatory assets
                
                
                -
                
                
                2Deferral
                    of
                    new regulatory assets
                
                
                (46
                )
                
                (46
                )General
                    taxes
                
                
                2
                
                
                3**Net
                    decrease in expenses**
                
                $
                (27
                )
                $
                (12
                )
 
 Purchased
          power
          costs increased in the second quarter and first six months of 2006 by $11
          million and $21 million, respectively, due to increased purchases to meet
          higher
          customer demand and higher composite unit prices. These increases were
          partially
          offset by increased NUG cost deferrals of $6 million in the second quarter
          and
          $4 million in the first six months of 2006. Other operating costs increased
          for
          both periods primarily due to higher transmission expenses, which increased
          as a
          result of the higher transmission prices discussed above. The deferral
          of new
          regulatory assets of $46 million reflected the May 4, 2006 PPUC approval
          of
          Met-Ed’s request to defer certain 2006 transmission-related costs. Met-Ed
          implemented the deferral accounting in the second quarter of 2006, which
          included $24 million for costs incurred in the first quarter of 2006 (see
          Regulatory Matters for further discussion). For both periods, general taxes
          increased primarily due to higher gross receipt taxes.
 
 **Capital
          Resources and Liquidity**
 
 Met-Ed’s
          cash
          requirements in 2006 for expenses, construction expenditures and scheduled
          debt
          maturities, are expected to be met with a combination of cash from operations,
          issuance of long-term debt, and short-term credit arrangements.
 
 *Changes
          in Cash
          Position*
 
 As
          of June 30, 2006,
          Met-Ed had $134,000 of cash and cash equivalents compared with $120,000
          as of
          December 31, 2005. The major sources for changes in these balances are
          summarized below.
 
 *Cash
          Flows From
          Operating Activities*
 
 Cash
          provided from
          operating activities in the first six months of 2006 and 2005 were as
          follows:
 
 **Six
                    Months Ended****June
                    30,****Operating
                    Cash Flows**
                
                **2006**
                
                **2005*****(In
                    millions)***Cash
                    earnings(1)
                
                $
                56
                
                $
                55Working
                    capital and other
                
                
                2
                
                
                33Net
                    cash
                    provided from operating activities
                
                $
                58
                
                $
                88
 (1) Cash
          earnings are a
          non-GAAP measure (see reconciliation below).
 
 Cash
          earnings (in
          the table above) are not a measure of performance calculated in accordance
          with
          GAAP. Met-Ed believes that cash earnings are a useful financial measure
          because
          it provides investors and management with an additional means of evaluating
          its
          cash-based operating performance.
 
 **Six
                        Months Ended****June
                        30,****Reconciliation
                        of Cash Earnings**
                    
                    **2006**
                    
                    **2005*****(In
                        millions)***Net
                        income
                        (GAAP)
                    
                    $
                    58
                    
                    $
                    32Non-cash
                        charges (credits):Provision
                        for
                        depreciation
                    
                    
                    21
                    
                    
                    23Amortization
                        of regulatory assets
                    
                    
                    56
                    
                    
                    54Deferred
                        costs
                        recoverable as regulatory assets
                    
                    
                    (51
                    )
                    
                    (48
                    )Deferral
                        of
                        new regulatory assets
                    
                    
                    (46
                    )
                    
                    -Deferred
                        income taxes and investment tax credits, net
                    
                    
                    23
                    
                    
                    (2
                    )Other
                        non-cash
                        charges
                    
                    
                    (5
                    )
                    
                    (4
                    )Cash
                        earnings
                        (Non-GAAP)
                    
                    $
                    56
                    
                    $
                    55
  149
  
 The
          $1 million
          increase in cash earnings is described above under “Results of Operations.” The
          $31 million working capital change primarily resulted from a $72 million
          decrease in cash provided from the settlement of receivables, a $7 million
          decrease in accrued taxes, a $3 million decrease in prepayments, a $2 million
          increase in cash collateral returned to suppliers, and a $4 million decrease
          in
          other accrued liabilities, partially offset by $57 million in decreased
          outflows
          for accounts payable.
 
 *Cash
          Flows From
          Financing Activities*
 
 Net
          cash used for
          financing activities was $2 million in first six months of 2006 compared
          to $51
          million in the same period of 2005. The decrease primarily reflects a $38
          million decrease in long-term debt redemptions and a $34 million decrease
          in
          common stock dividend payments to FirstEnergy in the first six months of
          2006,
          partially offset by a $23 million decrease in short-term
          borrowings.
 
 As
          of June 30, 2006,
          Met-Ed had approximately $32 million of cash and temporary investments
          (which
          included short-term notes receivable from associated companies) and $139
          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 PUCHA, 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 June 30, 2006 through Met-Ed
          Funding LLC, Met-Ed’s wholly owned subsidiary. As a separate legal entity with
          separate creditors, Met-Ed Funding would have to satisfy its obligations
          to
          creditors before any of its remaining assets could be made available to
          Met-Ed.
          As of June 30, 2006 the facility was drawn for $66 million. In June 2006,
          the
          facility was renewed until June 28, 2007. The annual facility fee is 0.125%
          on
          the entire finance limit.
 
 Under
          the terms of
          Met-Ed’s senior note indenture, FMBs may no longer be issued so long as the
          senior notes are outstanding. As of June 30, 2006, Met-Ed had the capability
          to
          issue $633 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 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 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 LOCs expiring up
          to one
          year from the date of issuance. The stated amount of outstanding LOCs will
          count
          against total commitments available under the facility and against the
          applicable borrower’s borrowing sub-limit. Total unused borrowing capability
          under the existing credit facilities and accounts receivable financing
          facilities totaled $264 million as of June 30, 2006.
 
 The
          revolving credit
          facility contains financial covenants requiring each Borrower to maintain
          a
          consolidated debt to total capitalization ratio of no more than 65%. As
          of
          June 30, 2006, Met-Ed’s debt to total capitalization as defined under the
          revolving credit facility was 38%.
 
 The
          facility does
          not contain any provisions that either restrict Met-Ed’s ability to borrow or
          accelerate repayment of outstanding advances as a result of any change
          in its
          credit ratings. Pricing is defined in “pricing grids”, whereby the cost of funds
          borrowed under the facility is related to Met-Ed's credit ratings.
 
 Met-Ed
          has the
          ability to borrow from its regulated affiliates and FirstEnergy to meet
          its
          short-term working capital requirements. FESC administers this money pool
          and
          tracks surplus funds of FirstEnergy and its regulated subsidiaries, as
          well as
          proceeds available from bank borrowings. Companies receiving a loan under
          the
          money pool agreements must repay the principal amount of such a loan, together
          with accrued interest, within 364 days of borrowing the funds. The rate
          of
          interest is the same for each company receiving a loan from the pool and
          is
          based on the average cost of funds available through the pool. The average
          interest rate for borrowings in the first six months of 2006 was
          4.86%.
 
 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 June 30, 2006, Met-Ed’s and
          FirstEnergy’s ratings outlook from S&P on all securities was stable. The
          ratings outlook from Moody’s and Fitch on all securities is
          positive.
 
  150
  *Cash
          Flows From
          Investing Activities*
 
 In
          the first six
          months of 2006, Met-Ed’s cash used for investing activities totaled $57 million,
          compared with $38 million in the same period of 2005. The increase primarily
          resulted from a $13 million increase in property additions and a $7 million
          increase in loans to associated companies. Expenditures for property additions
          primarily support Met-Ed’s energy delivery operations and reliability
          initiatives.
 
 During
          the last half
          of 2006, capital requirements for property additions are expected to be
          about
          $29 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
          $360 million, of which approximately $76 million applies to 2006. The
          capital spending is primarily for property additions supporting the distribution
          of electricity.
 
 **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. On April 1, 2006, Met-Ed elected to apply the normal purchase and
          normal
          sale exception to certain NUG power purchase agreements with an above-market
          fair value of $1 million (included in “Other” in the table below) in
          accordance with guidance in DIG C20. The change in the fair value of commodity
          derivative contracts related to energy production during the second quarter
          and
          first six months of 2006 is summarized in the following table:
 
 **Three
                    Months Ended**
                
                **Six
                    Months Ended****Increase
                    (Decrease) in the Fair Value**
                
                **June
                    30, 2006**
                
                **June
                    30, 2006****of
                    Commodity Derivative Contracts**
                
                **Non-Hedge**
                
                **Hedge**
                
                **Total**
                
                **Non-Hedge**
                
                **Hedge**
                
                **Total*****(In
                    millions)*****Change
                    in the Fair Value of****Commodity
                    Derivative Contracts:**Outstanding
                    net asset at beginning of period
                
                $
                24
                
                $
                -
                
                $
                24
                
                $
                27
                
                $
                -
                
                $
                27New
                    contract
                    value when entered
                
                
                -
                
                
                -
                
                
                -
                
                
                -
                
                
                -
                
                
                -Additions/change
                    in value of existing contracts
                
                
                -
                
                
                -
                
                
                -
                
                
                4
                
                
                -
                
                
                4Change
                    in
                    techniques/assumptions
                
                
                -
                
                
                -
                
                
                -
                
                
                -
                
                
                -
                
                
                -Settled
                    contracts
                
                
                (2
                )
                
                -
                
                
                (2
                )
                
                (9
                )
                
                -
                
                
                (9
                )Other
                
                
                1
                
                
                -
                
                
                1
                
                
                1
                
                
                -
                
                
                1**Net
                    Assets - Derivative Contracts**
                  **at
                    End
                    of Period****(1)**
                
                $
                23
                
                $
                -
                
                $
                23
                
                $
                23
                
                $
                -
                
                $
                23**Impact
                    of Changes in Commodity Derivative****Contracts(2)**Income
                    Statement effects (pre-tax)
                
                $
                (2
                )
                $
                -
                
                $
                (2
                )
                $
                (2
                )
                $
                -
                
                $
                (2
                )Balance
                    Sheet
                    effects:OCI
                    (pre-tax)
                
                $
                -
                
                $
                -
                
                $
                -
                
                $
                -
                
                $
                -
                
                $
                -Regulatory
                    liability
                
                $
                -
                
                $
                -
                
                $
                -
                
                $
                -
                
                $
                -
                
                $
                -
 
 (1)  Includes
          $23 million
          in non-hedge commodity derivative contract, which is offset by a regulatory
          liability.
 (2)  Represents
          the
          change in value of existing contracts, settled contracts and changes in
          techniques/assumptions.
 
  151
  Derivatives
          are
          included on the Consolidated Balance Sheet as of June 30, 2006 as
          follows:
 
 **Balance
                        Sheet Classification**
                    
                    
                    **Non-Hedge**
                    
                    
                    **Hedge**
                    
                    
                    **Total*****(In
                        millions)*****Non-Current-**Other
                        deferred
                        charges
                    
                    $
                    23
                    
                    $
                    -
                    
                    $
                    23Other
                        noncurrent liabilities
                    
                    
                    -
                    
                    
                    -
                    
                    
                    -Net
                        assets
                    
                    $
                    23
                    
                    $
                    -
                    
                    $
                    23
 
 The
          valuation of
          derivative contracts is based on observable market information to the extent
          that such information is available. In cases where such information is
          not
          available, Met-Ed relies on model-based information. The model provides
          estimates of future regional prices for electricity and an estimate of
          related
          price volatility. Met-Ed uses these results to develop estimates of fair
          value
          for financial reporting purposes and for internal management decision making.
          Sources of information for the valuation of commodity derivative contracts
          as of
          June 30, 2006 are summarized by year in the following table:
 
 **Source
                    of Information****Fair
                    Value by Contract Year**
                
                **2006**(1)
                
                **2007**
                
                **2008**
                
                **2009**
                
                **2010**
                
                **Thereafter**
                
                **Total*****(In
                    millions)***Other
                    external
                    sources(2)
                
                $
                5
                
                $
                5
                
                $
                5
                
                $
                -
                
                $
                -
                
                $
                -
                
                $
                15Prices
                    based
                    on models(3)
                
                
                -
                
                
                -
                
                
                -
                
                
                4
                
                
                4
                
                
                -
                
                
                8**Total**(3)
                
                **$**
                **5**
                
                **$**
                **5**
                
                **$**
                **5**
                
                **$**
                **4**
                
                **$**
                **4**
                
                **$**
                **-**
                
                **$**
                **23**
 
 (1)  For
          the last two
          quarters of 2006.
 (2)  Broker
          quote
          sheets.
 (3)  Includes
          $23 million
          from a non-hedge commodity derivative contract that is offset by a regulatory
          liability and does not affect earnings.
 
 Met-Ed
          performs
          sensitivity analyses to estimate its exposure to the market risk of its
          commodity positions. A hypothetical 10% adverse shift in quoted market
          prices in
          the near term on both of Met-Ed’s trading and non-trading derivative instruments
          would not have had a material effect on its consolidated financial position
          or
          cash flows as of June 30, 2006.
 
 *Equity
          Price
          Risk*
 
 Included
          in Met-Ed's
          nuclear decommissioning trusts are marketable equity securities carried
          at their
          market value of approximately $146 million and $142 million as of June 30,
          2006 and December 31, 2005, respectively. A hypothetical 10% decrease in
          prices quoted by stock exchanges would result in a $15 million reduction in
          fair value as of June 30, 2006.
 
 **Regulatory
          Matters**
  Regulatory assets are costs which have been authorized by the PPUC and
          the FERC
          for recovery from customers in future periods or for which authorization
          is
          probable. Without the probability of such authorization, costs currently
          recorded as regulatory assets would have been charged to income as incurred.
          All
          regulatory assets are expected to be recovered under the provisions of
          Met-Ed’s
          transition plan and rate restructuring plan. Met-Ed’s regulatory assets as of
          June 30, 2006 and December 31, 2005 were $359 million and
          $310 million, respectively.
  A February 2002 Commonwealth Court of Pennsylvania decision affirmed the
          June
          2001 PPUC decision regarding approval of the FirstEnergy/GPU merger, remanded
          the issues of quantification and allocation of merger savings to the PPUC
          and
          denied Met-Ed and Penelec the rate relief initially approved in the PPUC
          decision. On October 2, 2003, the PPUC issued an order concluding that
          the
          Commonwealth Court reversed the PPUC’s June 2001 order in its entirety. In
          accordance with the PPUC’s direction, Met-Ed and Penelec filed supplements to
          their tariffs that became effective in October 2003 and that reflected
          the CTC
          rates and shopping credits in effect prior to the June 2001 order.
  Met-Ed’s and Penelec’s combined portion of total net merger savings during 2001
          - 2004 is estimated to be approximately $51 million. A procedural schedule
          was established by the ALJ on January 17, 2006 and the companies filed
          initial testimony on March 1, 2006. On May 4, 2006, the PPUC
          consolidated this proceeding with the April 10, 2006 comprehensive rate
          filing proceeding discussed below. Met-Ed and Penelec are unable to predict
          the
          outcome of this matter.
 
  152
  In an October 16, 2003 order, the PPUC approved September 30, 2004 as
          the date for Met-Ed's NUG trust fund refunds. The PPUC order also denied
          its
          accounting treatment request regarding the CTC rate/shopping credit swap
          by
          requiring Met-Ed to treat the stipulated CTC rates that were in effect
          from
          January 1, 2002 on a retroactive basis. On October 22, 2003, Met-Ed
          filed an Objection with the Commonwealth Court asking that the Court reverse
          this PPUC finding; a Commonwealth Court judge subsequently denied its Objection
          on October 27, 2003 without explanation. On October 31, 2003, Met-Ed
          filed an Application for Clarification of the Court order with the Commonwealth
          Court, a Petition for Review of the PPUC's October 2 and October 16,
          2003 Orders, and an Application for Reargument, if the judge, in his
          clarification order, indicates that Met-Ed's Objection was intended to
          be denied
          on the merits. The Reargument Brief before the Commonwealth Court was filed
          on
          January 28, 2005. Oral arguments were held on June 8, 2006. On July
          19, 2006, the Commonwealth Court issued its decision affirming the PPUC’s prior
          orders. Although the decision denied the appeal of Met-Ed, it had previously
          accounted for the treatment of costs required by the PPUC’s October 2003
          orders.
  As
          of June 30, 2006, Met-Ed's and Penelec's regulatory deferrals pursuant
          to the
          1998 Restructuring Settlement (including the Phase 2 Proceedings) and the
          FirstEnergy/GPU Merger Settlement Stipulation were $335 million and
          $57 million, respectively. Penelec's $57 million is subject to the
          pending resolution of taxable income issues associated with NUG trust fund
          proceeds. The PPUC is reviewing a January 2006 change in Met-Ed’s and Penelec’s
          NUG purchase power stranded cost accounting methodology. If the PPUC orders
          Met-Ed and Penelec to reverse the change in accounting methodology, this
          would
          result in a pre-tax loss of $10.3 million for Met-Ed.
  On November 18, 2004, the FERC issued an order eliminating the RTOR for
          transmission service between the MISO and PJM regions. The FERC also ordered
          the
          MISO, PJM and the transmission owners within MISO and PJM to submit compliance
          filings containing a SECA mechanism to recover lost RTOR revenues during
          a
          16-month transition period from load serving entities. The FERC issued orders in
          2005 setting the SECA for hearing. ATSI, JCP&L, Met-Ed, Penelec, and FES
          continue to be involved in the FERC hearings concerning the calculation
          and
          imposition of the SECA charges. The hearing was held in May 2006. Initial
          briefs were submitted on June 9, 2006, and reply briefs were filed on June
          27, 2006. The 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 refund and hearing procedures. On
          June 30, 2005, the settling PJM transmission owners filed a request for
          rehearing of the May 31, 2005 order. On
          March 20, 2006, a settlement was filed with FERC in the formula rate
          proceeding that generally accepts the companies' formula rate proposal.
          The FERC
          issued an order approving this settlement on April 19, 2006. Hearings in
          the PJM rate design case concluded in April 2006. On July 13, 2006, an
          Initial
          Decision was issued by the ALJ. The ALJ adopted the Trial Staff’s position that
          the cost of all PJM transmission facilities should be recovered through
          a
          postage stamp rate. The ALJ recommended an April 1, 2006 effective date
          for this
          change in rate design. If the FERC accepts this recommendation, the transmission
          rate applicable to many load zones in PJM would increase. FirstEnergy believes
          that significant additional transmission revenues would have to be recovered
          from the JCP&L, Met-Ed and Penelec transmission zones within PJM. The
          Companies, as part of the Responsible Pricing Alliance, intend to submit
          a brief
          on exceptions within thirty days of the initial decision. Following submission
          of reply exceptions, the case is expected to be reviewed by the FERC with
          a
          decision anticipated in the fourth quarter of 2006.
 
 On
          January 12,
          2005, Met-Ed filed, before the PPUC, a request for deferral of
          transmission-related costs beginning January 1, 2005. The OCA, OSBA, OTS,
          MEIUG, PICA, Allegheny Electric Cooperative and Pennsylvania Rural Electric
          Association all intervened in the case. Met-Ed sought to consolidate this
          proceeding (and modified its request to provide deferral of 2006
          transmission-related costs only) with the comprehensive rate filing it
          made on
          April 10, 2006 as described below. On May 4, 2006, the PPUC approved
          the modified request. Accordingly, Met-Ed has deferred approximately
          $46 million, representing transmission costs that were incurred from
          January 1, 2006 through June 30, 2006. On June 5, 2006, the OCA filed
          before the Commonwealth Court a petition for review of the PPUC’s approval of
          the deferral. On July 12, 2006, the Commonwealth Court granted the PPUC’s motion
          to quash the OCA’s appeal. The ratemaking treatment of the deferral will be
          determined in the comprehensive rate filing proceeding discussed further
          below.
  Met-Ed
          purchases a portion of its PLR requirements from FES through a wholesale
          power
          sales agreement. Under this agreement, FES retains the supply obligation
          and the
          supply profit and loss risk for the portion of power supply requirements
          not
          self-supplied by Met-Ed under its contracts with NUGs and other unaffiliated
          suppliers. The FES arrangement reduces Met-Ed's exposure to high wholesale
          power
          prices by providing power at a fixed price for its uncommitted PLR energy
          costs
          during the term of the agreement with FES. The wholesale power sales agreement
          with FES could automatically be extended for each successive calendar year
          unless any party elects to cancel the agreement by November 1 of the preceding
          year. On November 1, 2005, FES and the other parties thereto amended the
          agreement to provide FES the right in 2006 to terminate the agreement at
          any
          time upon 60 days notice. On April 7, 2006, the parties to the
          wholesale power sales agreement entered into a Tolling Agreement that arises
          out
          of FES’ notice to Met-Ed that FES elected to exercise its right to terminate the
          wholesale power sales agreement effective midnight December 31, 2006,
          because that agreement is not economically sustainable to FES.
  153
  In lieu of allowing such termination to become effective as of December 31,
          2006, the parties agreed, pursuant to the Tolling Agreement, to amend the
          wholesale power sales agreement to provide as follows:
 
 1. The
          termination
          provisions of the wholesale power sales agreement will be tolled for one
          year
          until December 31, 2007, provided that during such tolling
          period:
 
 a. FES
          will be permitted to terminate the wholesale power sales agreement at any
          time
          with sixty days written notice;
 b. Met-Ed
          will procure through arrangements other than the wholesale power sales
          agreement
          beginning December 1, 2006 and ending December 31,
          2007,     approximately 33% of the amounts of capacity and
          energy necessary to satisfy its PLR obligations for which Committed Resources
          (i.e., non-utility generation under contract to Met-Ed, Met-Ed-owned generating
          facilities, purchased power contracts and distributed generation) have
          not been
          obtained; and
 c. FES
          will not be obligated to supply additional quantities of capacity and energy
          in
          the event that a supplier of Committed Resources defaults on its supply
          agreement.
 
 2. During
          the tolling
          period, FES will not act as an agent for Met-Ed in procuring the services
          under
          1.(b) above; and
 
 3. The
          pricing
          provision of the wholesale power sales agreement shall remain unchanged
          provided
          Met-Ed complies with the provisions of the Tolling Agreement and  any
          applicable provision of the wholesale power sales agreement.
   In the event that FES elects not to terminate the wholesale power sales
          agreement effective midnight December 31, 2007, similar tolling agreements
          effective after December 31, 2007 are expected to be considered by FES for
          subsequent years if Met-Ed procures through arrangements other than the
          wholesale power sales agreement approximately 64%, 83% and 95% of the additional
          amounts of capacity and energy necessary to satisfy its PLR obligations
          for
          2008, 2009 and 2010, respectively, for which Committed Resources have not
          been
          obtained from the market.
  The wholesale power sales agreement, as modified by the Tolling Agreement,
          requires Met-Ed to satisfy the portion of its PLR obligations currently
          supplied
          by FES from unaffiliated suppliers at prevailing prices, which are likely
          to be
          higher than the current price charged by FES under the current agreement
          and, as
          a result, Met-Ed’s purchased power costs could materially increase. If Met-Ed
          was to replace the entire FES supply at current market power prices without
          corresponding regulatory authorization to increase its generation prices
          to
          customers, Met-Ed would likely incur a significant increase in operating
          expenses and experience a material deterioration in credit quality metrics.
          Under such a scenario, Met-Ed's credit profile would no longer be expected
          to
          support an investment grade rating for its fixed income securities. There
          can be
          no assurance, however, that if FES ultimately determines to terminate,
          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 made a comprehensive rate filing with the PPUC on April 10, 2006
          that addresses a number of transmission, distribution and supply issues.
          If
          Met-Ed's preferred approach involving accounting deferrals is approved,
          the
          filing would increase annual revenues by $216 million. That filing
          includes, among other things, a request to charge customers for an increasing
          amount of market priced power procured through a CBP as the amount of supply
          provided under the existing FES agreement is phased out in accordance with
          the
          April 7, 2006 Tolling Agreement described above. Met-Ed
          also
          requested approval of the January 12, 2005 petition for the deferral of
          transmission-related costs discussed above, but only for those costs incurred
          during 2006. In this rate filing, Met-Ed also requested recovery of annual
          transmission and related costs incurred on or after January 1, 2007, plus
          the amortized portion of 2006 costs over a ten-year period, along with
          applicable carrying charges, through an adjustable rider similar to that
          implemented in Ohio. Changes in the
          recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded
          costs are
          also included in the filing. The filing contemplates a reduction in distribution
          rates for Met-Ed of $37 million annually. The PPUC suspended the effective
          date (June 10, 2006) of these rate changes for seven months after the
          filing as permitted under Pennsylvania law. If the
          PPUC adopts
          the overall positions taken in the intervenors’ testimony as filed, this would
          have a material adverse effect on the financial statements of FirstEnergy,
          Met-Ed and Penelec.Hearings are scheduled for late August 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 .
  154
 
 **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
          June 30, 2006, based on estimates of the total costs of cleanup, Met-Ed’s
          proportionate responsibility for such costs and the financial ability of
          other
          unaffiliated entities to pay.
  See Note 10(B) to the consolidated financial statements for further details
          and a complete discussion of environmental matters.
 
 ***Other
          Legal Proceedings***
 
 *Power
          Outages
          and Related Litigation*
  There are various lawsuits, claims (including claims for asbestos exposure)
          and
          proceedings related to Met-Ed’s normal business operations pending against
          Met-Ed. The other material items not otherwise discussed below are described
          in
          Note 10(C) to the consolidated financial statements.
  On August 14, 2003, various states and parts of southern Canada experienced
          widespread power outages. The outages affected approximately 1.4 million
          customers in FirstEnergy's service area. The U.S. - Canada Power System
          Outage
          Task Force’s final report in April 2004 on the outages concluded, among other
          things, that the problems leading to the outages began in FirstEnergy’s Ohio
          service area. Specifically,
          the
          final report concluded, among other things, that the initiation of the
          August 14, 2003 power outages resulted from an alleged failure of both
          FirstEnergy and ECAR to assess and understand perceived inadequacies within
          the
          FirstEnergy system; inadequate situational awareness of the developing
          conditions; and a perceived failure to adequately manage tree growth in
          certain
          transmission rights of way. The Task Force also concluded that there was
          a
          failure of the interconnected grid's reliability organizations (MISO and
          PJM) to
          provide effective real-time diagnostic support. The final report is publicly
          available through the Department of Energy’s Web site (www.doe.gov). FirstEnergy
          believes that the final report does not provide a complete and comprehensive
          picture of the conditions that contributed to the August 14, 2003 power
          outages and that it does not adequately address the underlying causes of
          the
          outages. FirstEnergy remains convinced that the outages cannot be explained
          by
          events on any one utility's system. The final report contained 46
“recommendations to prevent or minimize the scope of future blackouts.”
Forty-five of those recommendations related to broad industry or policy
          matters
          while one, including subparts, related to activities the Task Force recommended
          be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct
          the
          causes of the August 14, 2003 power outages. FirstEnergy implemented
          several initiatives, both prior to and since the August 14, 2003 power
          outages, which were independently verified by NERC as complete in 2004
          and were
          consistent with these and other recommendations and collectively enhance
          the
          reliability of its electric system. FirstEnergy’s implementation of these
          recommendations in 2004 included completion of the Task Force recommendations
          that were directed toward FirstEnergy. FirstEnergy is also proceeding with
          the
          implementation of the recommendations that were to be completed subsequent
          to
          2004 and will continue to periodically assess the FERC-ordered Reliability
          Study
          recommendations for forecasted 2009 system conditions, recognizing revised
          load
          forecasts and other changing system conditions which may impact the
          recommendations. Thus far, implementation of the recommendations has not
          required, nor is expected to require, substantial investment in new or
          material
          upgrades to existing equipment. The FERC or other applicable government
          agencies
          and reliability coordinators may, however, take a different view as to
          recommended enhancements or may recommend additional enhancements in the
          future
          as the result of adoption of mandatory reliability standards pursuant to
          the
          EPACT that could require additional material expenditures.
 
 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.
          FirstEnergy's motion to dismiss the matter was denied on June 2, 2006.
          FirstEnergy has since filed an appeal, which is pending. A responsive pleading
          to this matter has been filed. Also, the complaint has been amended to
          include
          an additional party. No estimate of potential liability has been undertaken
          in
          this matter.
  155
  FirstEnergy
          is vigorously defending these actions, but cannot predict the outcome of
          any of
          these proceedings or whether any further regulatory proceedings or legal
          actions
          may be initiated against the Companies. Although unable to predict the
          impact of
          these proceedings, if FirstEnergy or its subsidiaries were ultimately determined
          to have legal liability in connection with these proceedings, it could
          have a
          material adverse effect on FirstEnergy's or its subsidiaries' financial
          condition, results of operations and cash flows.
 
 **New
          Accounting Standards and Interpretations**
 
 *FSP
          FIN 46(R)-6
          - “Determining the Variability to Be Considered in Applying FASB interpretation
          No. 46(R)”*
 
 In
          April 2006, the
          FASB issued FSP FIN 46(R)-6 that addresses how a reporting enterprise should
          determine the variability to be considered in applying FASB interpretation
          No.
          46 (revised December 2003). FirstEnergy adopted FIN 46(R) in the first
          quarter
          of 2004, consolidating VIE’s when FirstEnergy or one of its subsidiaries is
          determined to be the VIE’s primary beneficiary. The variability that is
          considered in applying interpretation 46(R) affects the determination of
          (a)
          whether the entity is a VIE; (b) which interests are variable interests
          in the
          entity; and (c) which party, if any, is the primary beneficiary of the
          VIE. This
          FSP states that the variability to be considered shall be based on an analysis
          of the design of the entity, involving two steps:
  Step
                    1:
                Analyze
                    the
                    nature of the risks in the entityStep
                    2:
                Determine
                    the
                    purpose(s) for which the entity was created and determine the
                    variability
                    the entity is designed to create and pass along to its interest
                    holders.
 
 After
          determining
          the variability to consider, the reporting enterprise can determine which
          interests are designed to absorb that variability. The guidance in this
          FSP is
          applied prospectively to all entities (including newly created entities)
          with
          which that enterprise first becomes involved and to all entities previously
          required to be analyzed under interpretation 46(R) when a reconsideration
          event
          has occurred after July 1, 2006. Met-Ed does not expect this Statement
          to have a
          material impact on its financial statements.
 
 *FIN
          48 -
“Accounting for Uncertainty in Income Taxes - an interpretation of FASB
          Statement No. 109.”*
 
 In
          June 2006, the
          FASB issued FIN 48 which clarifies the accounting for uncertainty in income
          taxes recognized in an enterprise’s financial statements in accordance with FASB
          Statement No. 109, “Accounting for Income Taxes.” This interpretation prescribes
          a recognition threshold and measurement attribute for the financial statement
          recognition and measurement of a tax position taken or expected to be taken
          on a
          tax return. This interpretation also provides guidance on derecognition,
          classification, interest, penalties, accounting in interim periods, disclosure
          and transition. The evaluation of a tax position in accordance with this
          interpretation will be a two-step process. The first step will determine
          if it
          is more likely than not that a tax position will be sustained upon examination
          and should therefore be recognized. The second step will measure a tax
          position
          that meets the more likely than not recognition threshold to determine
          the
          amount of benefit to recognize in the financial statements. This interpretation
          is effective for fiscal years beginning after December 15, 2006. Met-Ed
          is
          currently evaluating the impact of this Statement.
  156
  
 **PENNSYLVANIA
                        ELECTRIC
                        COMPANY****CONSOLIDATED
                        STATEMENTS OF INCOME AND COMPREHENSIVE
                        INCOME****(Unaudited)****Three
                        Months Ended**
                    
                    **Six
                        Months Ended****June
                        30,**
                    
                    **June
                        30,****2006**
                    
                    **2005**
                    
                    **2006**
                    
                    **2005*****(In
                        thousands)*****REVENUES**
                    
                    $
                    264,999
                    
                    $
                    262,097
                    
                    $
                    556,751
                    
                    $
                    556,026**EXPENSES:**Purchased
                        power
                    
                    
                    146,875
                    
                    
                    139,292
                    
                    
                    308,516
                    
                    
                    289,549Other
                        operating costs
                    
                    
                    48,133
                    
                    
                    62,794
                    
                    
                    86,475
                    
                    
                    116,607Provision
                        for
                        depreciation
                    
                    
                    11,798
                    
                    
                    12,479
                    
                    
                    24,441
                    
                    
                    24,985Amortization
                        of regulatory assets
                    
                    
                    12,979
                    
                    
                    13,118
                    
                    
                    27,794
                    
                    
                    26,303Deferral
                        of
                        new regulatory assets
                    
                    
                    (11,815
                    )
                    
                    -
                    
                    
                    (11,815
                    )
                    
                    -General
                        taxes
                    
                    
                    17,458
                    
                    
                    16,134
                    
                    
                    36,847
                    
                    
                    34,340Total
                        expenses
                    
                    
                    225,428
                    
                    
                    243,817
                    
                    
                    472,258
                    
                    
                    491,784**OPERATING
                        INCOME**
                    
                    
                    39,571
                    
                    
                    18,280
                    
                    
                    84,493
                    
                    
                    64,242**OTHER
                        INCOME (EXPENSE):**Miscellaneous
                        income
                    
                    
                    1,627
                    
                    
                    938
                    
                    
                    3,997
                    
                    
                    1,268Interest
                        expense
                    
                    
                    (11,599
                    )
                    
                    (10,091
                    )
                    
                    (22,135
                    )
                    
                    (19,738
                    )Capitalized
                        interest
                    
                    
                    422
                    
                    
                    264
                    
                    
                    769
                    
                    
                    389Total
                        other
                        income (expense)
                    
                    
                    (9,550
                    )
                    
                    (8,889
                    )
                    
                    (17,369
                    )
                    
                    (18,081
                    )**INCOME
                        TAXES**
                    
                    
                    14,564
                    
                    
                    3,554
                    
                    
                    28,518
                    
                    
                    18,940**NET
                        INCOME**
                    
                    
                    15,457
                    
                    
                    5,837
                    
                    
                    38,606
                    
                    
                    27,221**OTHER
                        COMPREHENSIVE INCOME:**Unrealized
                        gain on derivative hedges
                    
                    
                    16
                    
                    
                    16
                    
                    
                    32
                    
                    
                    32Unrealized
                        loss on available for sale securities
                    
                    
                    (14
                    )
                    
                    (18
                    )
                    
                    (18
                    )
                    
                    (21
                    )Other
                        comprehensive income (loss)
                    
                    
                    2
                    
                    
                    (2
                    )
                    
                    14
                    
                    
                    11Income
                        tax
                        expense (benefit) related to othercomprehensive
                        income
                    
                    
                    1
                    
                    
                    (6
                    )
                    
                    7
                    
                    
                    -Other
                        comprehensive income, net of tax
                    
                    
                    1
                    
                    
                    4
                    
                    
                    7
                    
                    
                    11**TOTAL
                        COMPREHENSIVE INCOME**
                    
                    $
                    15,458
                    
                    $
                    5,841
                    
                    $
                    38,613
                    
                    $
                    27,232The
                        preceding
                        Notes to Consolidated Financial Statements as they relate
                        to Pennsylvania
                        Electric Company are an integral part
                        of these
                        statements.
   157
  **PENNSYLVANIA
                        ELECTRIC COMPANY****CONSOLIDATED
                        BALANCE SHEETS****(Unaudited)****June
                        30,**
                    
                    **December
                        31,****2006**
                    
                    **2005*****(In
                        thousands)*****ASSETS****CURRENT
                        ASSETS:**Cash
                        and cash
                        equivalents
                    
                    $
                    49
                    
                    $
                    35Receivables-Customers
                        (less accumulated provisions of $4,044,000 and $4,184,000,respectively,
                        for uncollectible accounts)
                    
                    
                    119,103
                    
                    
                    129,960Associated
                        companies
                    
                    
                    2,173
                    
                    
                    18,626Other
                    
                    
                    9,625
                    
                    
                    12,800Notes
                        receivable from associated companies
                    
                    
                    21,090
                    
                    
                    17,624Prepaid
                        gross
                        receipts taxes
                    
                    
                    22,626
                    
                    
                    -Prepayments
                        and other
                    
                    
                    3,874
                    
                    
                    7,936178,540
                    
                    
                    186,981**UTILITY
                        PLANT:**In
                        service
                    
                    
                    2,095,438
                    
                    
                    2,043,885Less
                        -
                        Accumulated provision for depreciation
                    
                    
                    793,523
                    
                    
                    784,4941,301,915
                    
                    
                    1,259,391Construction
                        work in progress
                    
                    
                    27,761
                    
                    
                    30,8881,329,676
                    
                    
                    1,290,279**OTHER
                        PROPERTY AND INVESTMENTS:**Nuclear
                        plant
                        decommissioning trusts
                    
                    
                    115,252
                    
                    
                    113,368Non-utility
                        generation trusts
                    
                    
                    97,866
                    
                    
                    96,761Other
                    
                    
                    531
                    
                    
                    918213,649
                    
                    
                    211,047**DEFERRED
                        CHARGES AND OTHER ASSETS:**Goodwill
                    
                    
                    877,651
                    
                    
                    882,344Prepaid
                        pension costs
                    
                    
                    92,307
                    
                    
                    89,637Other
                    
                    
                    37,150
                    
                    
                    38,2891,007,108
                    
                    
                    1,010,270$
                    2,728,973
                    
                    $
                    2,698,577**LIABILITIES
                        AND CAPITALIZATION****CURRENT
                        LIABILITIES:**Short-term
                        borrowings-Associated
                        companies
                    
                    $
                    220,801
                    
                    $
                    261,159Other
                    
                    
                    67,000
                    
                    
                    -Accounts
                        payable-Associated
                        companies
                    
                    
                    16,256
                    
                    
                    33,770Other
                    
                    
                    46,783
                    
                    
                    38,277Accrued
                        taxes
                    
                    
                    17,148
                    
                    
                    27,905Accrued
                        interest
                    
                    
                    9,094
                    
                    
                    8,905Other
                    
                    
                    17,796
                    
                    
                    19,756394,878
                    
                    
                    389,772**CAPITALIZATION:**Common
                        stockholder's equity-Common
                        stock,
                        $20 par value, authorized 5,400,000 shares-5,290,596
                        shares outstanding
                    
                    
                    105,812
                    
                    
                    105,812Other
                        paid-in
                        capital
                    
                    
                    1,197,889
                    
                    
                    1,202,551Accumulated
                        other comprehensive loss
                    
                    
                    (302
                    )
                    
                    (309
                    )Retained
                        earnings
                    
                    
                    64,429
                    
                    
                    25,823Total
                        common
                        stockholder's equity
                    
                    
                    1,367,828
                    
                    
                    1,333,877Long-term
                        debt
                        and other long-term obligations
                    
                    
                    476,904
                    
                    
                    476,5041,844,732
                    
                    
                    1,810,381**NONCURRENT
                        LIABILITIES:**Regulatory
                        liabilities
                    
                    
                    135,494
                    
                    
                    162,937Accumulated
                        deferred income taxes
                    
                    
                    119,912
                    
                    
                    106,871Retirement
                        benefits
                    
                    
                    105,980
                    
                    
                    102,046Asset
                        retirement obligation
                    
                    
                    74,574
                    
                    
                    72,295Other
                    
                    
                    53,403
                    
                    
                    54,275489,363
                    
                    
                    498,424**COMMITMENTS
                        AND CONTINGENCIES (Note 10)**$
                    2,728,973
                    
                    $
                    2,698,577The
                        preceding
                        Notes to Consolidated Financial Statements as they relate
                        to Pennsylvania
                        Electric Company are an integral part of these balance
                        sheets.
   158
 
 **PENNSYLVANIA
                        ELECTRIC COMPANY****CONSOLIDATED
                        STATEMENTS OF CASH FLOWS****(Unaudited)****Six
                        Months Ended****June
                        30,****2006**
                    
                    **2005*****(In
                        thousands)*****CASH
                        FLOWS FROM OPERATING ACTIVITIES:**Net
                        income
                    
                    $
                    38,606
                    
                    $
                    27,221Adjustments
                        to
                        reconcile net income to net cash from operating activities
                        -Provision
                        for
                        depreciation
                    
                    
                    24,441
                    
                    
                    24,985Amortization
                        of regulatory assets
                    
                    
                    27,794
                    
                    
                    26,303Deferral
                        of
                        new regulatory assets
                    
                    
                    (11,815
                    )
                    
                    -Deferred
                        costs
                        recoverable as regulatory assets
                    
                    
                    (54,092
                    )
                    
                    (35,946
                    )Deferred
                        income taxes and investment tax credits, net
                    
                    
                    13,206
                    
                    
                    2,647Accrued
                        retirement benefit obligations
                    
                    
                    1,264
                    
                    
                    1,905Accrued
                        compensation, net
                    
                    
                    (371
                    )
                    
                    (2,386
                    )Decrease
                        (increase) in operating assets -Receivables
                    
                    
                    30,485
                    
                    
                    79,602Prepayments
                        and other current assets
                    
                    
                    (18,565
                    )
                    
                    (22,107
                    )Increase
                        (decrease) in operating liabilities -Accounts
                        payable
                    
                    
                    (9,008
                    )
                    
                    (20,333
                    )Accrued
                        taxes
                    
                    
                    (10,756
                    )
                    
                    10,728Accrued
                        interest
                    
                    
                    190
                    
                    
                    (34
                    )Other
                    
                    
                    8,817
                    
                    
                    4,365Net
                        cash
                        provided from operating activities
                    
                    
                    40,196
                    
                    
                    96,950**CASH
                        FLOWS FROM FINANCING ACTIVITIES:**New
                        Financing
                        -Short-term
                        borrowings, net
                    
                    
                    26,642
                    
                    
                    -Redemptions
                        and Repayments -Long-term
                        debt
                    
                    
                    -
                    
                    
                    (3,521
                    )Short-term
                        borrowings, net
                    
                    
                    -
                    
                    
                    (36,608
                    )Dividend
                        Payments -Common
                        stock
                    
                    
                    -
                    
                    
                    (30,000
                    )Net
                        cash
                        provided from (used for) financing activities
                    
                    
                    26,642
                    
                    
                    (70,129
                    )**CASH
                        FLOWS FROM INVESTING ACTIVITIES:**Property
                        additions
                    
                    
                    (60,747
                    )
                    
                    (33,683
                    )Loan
                        repayments from (loans to) associated companies, net
                    
                    
                    (3,466
                    )
                    
                    7,011Proceeds
                        from
                        nuclear decommissioning trust fund sales
                    
                    
                    51,536
                    
                    
                    24,127Investments
                        in
                        nuclear decommissioning trust funds
                    
                    
                    (51,536
                    )
                    
                    (24,127
                    )Other,
                        net
                    
                    
                    (2,611
                    )
                    
                    (150
                    )Net
                        cash used
                        for investing activities
                    
                    
                    (66,824
                    )
                    
                    (26,822
                    )Net
                        increase
                        (decrease) in cash and cash equivalents
                    
                    
                    14
                    
                    
                    (1
                    )Cash
                        and cash
                        equivalents at beginning of period
                    
                    
                    35
                    
                    
                    36Cash
                        and cash
                        equivalents at end of period
                    
                    $
                    49
                    
                    $
                    35The
                        preceding
                        Notes to Consolidated Financial Statements as they relate
                        to Pennsylvania
                        Electric Company are an integral
                        part
                        of these
                        statements.
   159
    ***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 June 30, 2006, and the related consolidated statements
          of
          income and comprehensive income for each of the three-month and six-month
          periods ended June 30, 2006 and 2005 and the consolidated statement of
          cash
          flows for the six-month period ended June 30, 2006 and 2005. These interim
          financial statements are the responsibility of the Company’s
          management.
 
 We
          conducted our
          review in accordance with the standards of the Public Company Accounting
          Oversight Board (United States). A review of interim financial information
          consists principally of applying analytical procedures and making inquiries
          of
          persons responsible for financial and accounting matters. It is substantially
          less in scope than an audit conducted in accordance with the standards
          of the
          Public Company Accounting Oversight Board, the objective of which is the
          expression of an opinion regarding the financial statements taken as a
          whole.
          Accordingly, we do not express such an opinion.
 
 Based
          on our review,
          we are not aware of any material modifications that should be made to the
          accompanying consolidated interim financial statements for them to be in
          conformity with accounting principles generally accepted in the United
          States of
          America.
 
 We
          have previously
          audited, in accordance with the standards of the Public Company Accounting
          Oversight Board (United States), the consolidated balance sheet as of December
          31, 2005, and the related consolidated statements of income, capitalization,
          common stockholder’s equity, preferred stock, cash flows and taxes for the year
          then ended (not presented herein), and in our report [which contained references
          to the Company’s change in its method of accounting for asset retirement
          obligations as of January 1, 2003 and conditional asset retirement obligations
          as of December 31, 2005 as discussed in Note 2(G) and Note 9 to those
          consolidated financial statements] dated February 27, 2006, we expressed
          an
          unqualified opinion on those consolidated financial statements. In our
          opinion,
          the information set forth in the accompanying consolidated balance sheet
          as of
          December 31, 2005, is fairly stated in all material respects in relation
          to the
          consolidated balance sheet from which it has been derived.
 
 
 
 
 PricewaterhouseCoopers
          LLP
 Cleveland,
          Ohio
 August
          4,
          2006
 
 
  160
  **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
          second quarter of 2006 increased to $15 million, compared to $6 million in
          the second quarter of 2005. In the first six months of 2006, net income
          increased to $39 million, compared to $27 million in the first six months
          of
          2005. The increase in net income for both periods resulted from lower other
          operating costs, deferral of new regulatory assets, and higher revenues
          which
          were partially offset by higher purchased power costs, general taxes and
          interest expense, as discussed below.
 
 *Revenues*
 
 Revenues
          increased
          by $3 million in the second quarter of 2006 and $1 million in the first
          six
          months of 2006, compared to the same periods of 2005. Increases in both
          periods
          were due primarily to higher retail generation revenues partially offset
          by
          lower transmission and distribution revenues. Retail generation
          revenues increased by $12 million in the second quarter of 2006 and $23
          million
          for the first six months of 2006 primarily due to higher KWH sales to industrial
          customers and higher composite unit prices in all customer classes. Industrial
          sales increased $8 million for the second quarter of 2006 and $15 million
          for
          the first six months of 2006 primarily due to the return of customers to
          Penelec
          from alternative suppliers. Generation service provided by alternative
          suppliers
          as a percent of total industrial sales in Penelec’s service area decreased by
          12.1 percentage points and 13.2 percentage points in the second quarter
          and the
          first six months of 2006, respectively . The
          higher composite
          unit prices also increased generation revenues from residential customers
          by
          $1 million and $3 million and from commercial customers by $3 million
          and $5 million in the second quarter and first six months of 2006, respectively.
 
 Distribution
          revenues decreased by $1 million in the second quarter of 2006 and by $3
          million in the first six months of 2006, compared with the same periods
          of 2005.
          The decreases were primarily due to 1.1% and 1.9% decreases in KWH deliveries
          in
          the second quarter and first six months of 2006, respectively. Reduced
          KWH
          deliveries reflected milder temperatures in both periods of 2006 compared
          with
          the same periods of 2005. Those reductions were partially offset by slightly
          higher composite unit prices during the periods. Transmission revenues
          decreased
          by $8 million in the second quarter of 2006 and $20 million in the first
          six
          months of 2006 due to lower transmission load requirements and lower prices.
          The
          decreased loads for the first six months of 2006 (and related lower congestion
          revenues) resulted from milder temperatures, as demonstrated by a 40.4%
          decrease
          in cooling degree days and a 14.4% decrease in heating degree days compared
          to
          the same period in 2005, which resulted in decreased transmission expenses
          discussed further below. For
          the first six
          months of 2006, other revenues also increased for a payment received in
          the
          first quarter of 2006 under a contract provision associated with the prior
          sale
          of TMI Unit 1. Under the contract, additional payments are received if
          subsequent energy prices rise above specified levels, which occurred. This
          payment was credited to Penelec’s customers, resulting in no net earnings
          effect.
 
 Changes
          in KWH sales
          by customer class in the second quarter and first six months of 2006 compared
          to
          the respective periods in 2005 are summarized in the following
          table:
 
 **Three**
                
                **Six****Changes
                    in KWH Sales**
                
                **Months**
                
                **Months****Increase
                    (Decrease)**Retail
                    Electric Generation:Residential
                
                
                (1.9
                )%
                
                (2.1
                )%Commercial
                
                
                -
                
                
                (0.7
                )%Industrial
                
                
                14.8
                %
                
                14.9
                %**Total
                    Retail Electric Generation Sales**
                
                
                **3.8**
                **%**
                
                **3.3**
                **%**Distribution
                    Deliveries:Residential
                
                
                (2.1
                )%
                
                (2.2
                )%Commercial
                
                
                (1.0
                )%
                
                (1.7
                )%Industrial
                
                
                (0.5
                )%
                
                (1.8
                )%**Total
                    Distribution Deliveries**
                
                
                **(1.1**
                **)%**
                
                **(1.9**
                **)%**
  161
  *Expenses*
 
 Total
          expenses
          decreased by $19 million or 7.5% in the second quarter of 2006 and $20
          million
          or 4.0% in the first six months of 2006 compared with the same periods
          in 2005.
          The following table presents changes from the prior year by expense category:
 
 **Three**
                
                **Six****Expenses
                    Changes**
                
                **Months**
                
                **Months*****(In
                    millions)*****Increase
                    (Decrease)**Purchased
                    power costs
                
                $
                8
                
                $
                19Other
                    operating costs
                
                
                (15)
                
                
                (30)Provision
                    for
                    depreciation
                
                
                (1)
                
                
                (1)Amortization
                    of regulatory assets
                
                
                -
                
                
                1Deferral
                    of
                    new regulatory assets
                
                
                (12)
                
                
                (12)General
                    taxes
                
                
                1
                
                
                3**Net
                    decrease in expenses**
                
                $
                (19)
                
                $
                (20)
 
 Purchased
          power
          costs increased by $8 million or 5.4% in the second quarter and $19 million
          or
          6.6% in the first six months of 2006 compared to the same periods in 2005.
          The
          increases in both periods were primarily attributable to higher unit costs
          from
          non-affiliated suppliers and increased KWH purchased to meet retail generation
          sales requirements. These increases were partially offset by increased
          NUG
          expense deferrals of $4 million in both the second quarter and in the first
          six
          months of 2006. Other operating costs decreased due to lower transmission
          expenses resulting from lower congestion charges. Expenses were further
          reduced
          due to higher levels of construction activities in the second quarter of
          2006
          compared to a higher level of maintenance activities in the same period
          of 2005
          for energy delivery operations and reliability initiatives. The deferral
          of new
          regulatory assets of $12 million reflected the May 4, 2006 PPUC approval
          of
          Penelec’s request to defer certain 2006 transmission-related costs. Penelec
          implemented the deferral accounting in the second quarter of 2006, which
          included $4 million for costs incurred in the first quarter of 2006 (see
          Regulatory Matters for further discussion). For
          both periods,
          general taxes increased primarily due to higher Pennsylvania gross receipt
          taxes.
 
 **Capital
          Resources and Liquidity**
 
 Penelec’s
          cash
          requirements in 2006 for expenses, construction expenditures and scheduled
          debt
          maturities, are expected to be met by a combination of cash from operations
          and
          short-term credit arrangements.
 
 *Changes
          in Cash
          Position*
 
 As
          of June 30,
          2006, Penelec had $49,000 of cash and cash equivalents compared with $35,000
          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 six months of 2006 and 2005 were as follows:
 
 **Six
                    Months Ended****June
                    30,****Operating
                    Cash Flows**
                
                **2006**
                
                **2005*****(In
                    millions)***Cash
                    earnings(1)
                
                $
                39
                
                $
                45Working
                    capital and other
                
                
                1
                
                
                52Net
                    cash
                    provided from operating activities
                
                $
                40
                
                $
                97
 (1) Cash earnings are a
          non-GAAP measure (see reconciliation below).
 
 Cash
          earnings (in
          the table above) are not a measure of performance calculated in accordance
          with
          GAAP. Penelec believes that cash earnings are a useful financial measure
          because
          it provides investors and management with an additional means of evaluating
          its
          cash-based operating performance.
  162
  
 **Six
                    Months Ended****June
                    30,****Reconciliation
                    of Cash Earnings**
                
                **2006**
                
                **2005*****(In
                    millions)***Net
                    income
                    (GAAP)
                
                $
                39
                
                $
                27Non-cash
                    charges (credits):Provision
                    for
                    depreciation
                
                
                24
                
                
                25Amortization
                    of regulatory assets
                
                
                28
                
                
                26Deferral
                    of
                    new regulatory assets
                
                
                (12
                )
                
                -Deferred
                    costs
                    recoverable as regulatory assets
                
                
                (54
                )
                
                (36
                )Deferred
                    income taxes and investment tax credits, net
                
                
                13
                
                
                3Other
                    non-cash
                    items
                
                
                1
                
                
                -Cash
                    earnings
                    (Non-GAAP)
                
                $
                39
                
                $
                45
 
 The
          $6 million
          decrease in cash earnings is described above under “Results of Operations.” The
          $51 million decrease from working capital primarily resulted from a
          decrease of $49 million in cash provided from the settlement of receivables
          and
          a $21 million decrease in accrued taxes, partially offset by decreased
          outflows of $11 million for accounts payable and $4 million for
          prepayments.
 
 *Cash
          Flows From
          Financing Activities*
 
 Net
          cash provided
          from financing activities was $27 million in the first six months of 2006
          compared to net cash used for financing activities of $70 million in the
          first six months of 2005. The change reflects a $63 million increase in
          short-term borrowings, a $30 million reduction in common stock dividend
          payments to FirstEnergy and a $4 million decrease in long-term debt redemptions.
 
 Penelec
          had
          approximately $21 million of cash and temporary investments (which includes
          short-term notes receivable from associated companies) and approximately
          $288
          million of short-term indebtedness as of June 30, 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 June 30, 2006 through
          Penelec Funding, Penelec's wholly owned subsidiary. As a separate legal
          entity
          with separate creditors, Penelec Funding would have to satisfy its obligations
          to creditors before any of its remaining assets could be made available
          to
          Penelec. As of June 30, 2006 the facility was drawn for $67 million.
          In June 2006, the facility was renewed until July 28, 2007. The annual
          facility
          fee is 0.125% on the entire finance limit.
 
 Penelec
          will not
          issue FMB other than as collateral for senior notes, since its senior note
          indentures prohibit (subject to certain exceptions) Penelec from issuing
          any
          debt which is senior to the senior notes. As of June 30, 2006, Penelec had
          the ability to issue $50 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 $258 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
          June 30, 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.
  163
  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
          six months of 2006 was 4.86%.
 
 Penelec’s
          access to
          capital markets and costs of financing are dependent on the ratings of
          its
          securities and that of FirstEnergy. The ratings outlook from S&P on all
          securities is stable. The ratings outlook from Moody's and Fitch on all
          securities is positive.
 
 *Cash
          Flows From
          Investing Activities*
  In the first six months of 2006, net cash used for investing activities
          totaled
          $67 million compared to $27 million in the first six months of 2005. The
          increase primarily resulted from $27 million in increased property additions
          and
          a $10 million increase in loans to associated companies. Expenditures for
          property additions primarily support Penelec’s energy delivery operations and
          reliability initiatives.
 
 During
          the last half
          of 2006, capital requirements for property additions are expected to be
          approximately $46 million. Penelec’s capital spending for the period
          2006-2010 is expected to be approximately $496 million, of which
          approximately $110 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. On April
          1,
          2006, Penelec elected to apply the normal purchase and normal sale exception
          to
          certain NUG power purchase agreements with a fair value of $14 million
          (included
          in “Other” in the table below) in accordance with guidance in DIG C20. The
          change in the fair value of commodity derivative contracts related to energy
          production during the second quarter and first six months of 2006 is summarized
          in the following table:
 
 **Three
                    Months Ended**
                
                **Six
                    Months Ended****Increase
                    (Decrease) in the Fair Value**
                
                **June
                    30, 2006**
                
                **June
                    30, 2006****of
                    Commodity Derivative Contracts**
                
                **Non-Hedge**
                
                **Hedge**
                
                **Total**
                
                **Non-Hedge**
                
                **Hedge**
                
                **Total*****(In
                    millions)*****Change
                    in the Fair Value of****Commodity
                    Derivative Contracts:**Outstanding
                    net asset at beginning of period
                
                $
                30
                
                $
                -
                
                $
                30
                
                $
                27
                
                $
                -
                
                $
                27New
                    contract
                    value when entered
                
                
                -
                
                
                -
                
                
                -
                
                
                -
                
                
                -
                
                
                -Additions/change
                    in value of existing contracts
                
                
                -
                
                
                -
                
                
                -
                
                
                2
                
                
                -
                
                
                2Change
                    in
                    techniques/assumptions
                
                
                -
                
                
                -
                
                
                -
                
                
                -
                
                
                -
                
                
                -Settled
                    contracts
                
                
                (4)
                
                
                -
                
                
                (4)
                
                
                (3)
                
                
                -
                
                
                (3)Other
                
                
                (14)
                
                
                -
                
                
                (14)
                
                
                (14)
                
                
                -
                
                
                (14)**Net
                    Assets - Derivative Contracts**
                  **at
                    End
                    of Period****(1)**
                
                $
                12
                
                $
                -
                
                $
                12
                
                $
                12
                
                $
                -
                
                $
                12**Impact
                    of Changes in Commodity Derivative Contracts****(3)**Income
                    Statement effects (pre-tax)
                
                $
                (4)
                
                $
                -
                
                $
                (4)
                
                $
                (4)
                
                $
                -
                
                $
                (4)Balance
                    Sheet
                    effects:OCI
                    (pre-tax)
                
                $
                -
                
                $
                -
                
                $
                -
                
                $
                -
                
                $
                -
                
                $
                -Regulatory
                    liability
                
                $
                -
                
                $
                -
                
                $
                -
                
                $
                3
                
                $
                -
                
                $
                3
 (1)  Includes
          $11 million
          in a non-hedge commodity derivative contract which is offset by a regulatory
          liability.
 (2)  Represents
          the
          increase in value of existing contracts, settled contracts and changes
          in
          techniques/assumptions.
  164
  Derivatives
          are
          included on the Consolidated Balance Sheet as of June 30, 2006 as
          follows:
 
 **Balance
                    Sheet Classification**
                
                **Non-Hedge**
                
                **Hedge**
                
                **Total*****(In
                    millions)*****Non-Current-**Other
                    deferred
                    charges
                
                
                12
                
                
                -
                
                
                12Other
                    noncurrent liabilities
                
                
                -
                
                
                -
                
                
                -Net
                    assets
                
                $
                12
                
                $
                -
                
                $
                12
 
 The
          valuation of
          derivative contracts is based on observable market information to the extent
          that such information is available. In cases where such information is
          not
          available, Penelec relies on model-based information. The model provides
          estimates of future regional prices for electricity and an estimate of
          related
          price volatility. Penelec uses these results to develop estimates of fair
          value
          for financial reporting purposes and for internal management decision making.
          Sources of information for the valuation of commodity derivative contracts
          as of
          June 30, 2006 are summarized by year in the following table:
 
 **Source
                    of Information****Fair
                    Value by Contract Year**
                
                **2006**(1)
                
                **2007**
                
                **2008**
                
                **2009**
                
                **2010**
                
                **Thereafter**
                
                **Total*****(In
                    millions)***Other
                    external
                    sources(2)
                
                $
                3
                
                $
                3
                
                $
                2
                
                $
                -
                
                $
                -
                
                $
                -
                
                $
                8Prices
                    based
                    on models(3)
                
                
                -
                
                
                -
                
                
                -
                
                
                2
                
                
                2
                
                
                -
                
                
                4**Total**(3)
                
                **$**
                **3**
                
                **$**
                **3**
                
                **$**
                **2**
                
                **$**
                **2**
                
                **$**
                **2**
                
                **$**
                **-**
                
                **$**
                **12**
 
 (1)  For
          the last two
          quarters of 2006.
 (2)  Broker
          quote
          sheets.
 (3)  Includes
          $11 million
          from a non-hedge commodity derivative contract that is offset by a regulatory
          liability and does not affect earnings.
 
 Penelec performs
          sensitivity
          analyses to estimate its exposure to the market risk of its commodity positions.
          A hypothetical 10% adverse shift in quoted market prices in the near term
          on
          both of Penelec's trading and non-trading derivative instruments would
          not have
          had a material effect on its consolidated financial position or cash flows
          as of
          June 30, 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 $64 million and $62 million as of June 30,
          2006 and December 31, 2005, respectively. A hypothetical 10% decrease in
          prices quoted by stock exchanges would result in a $6 million reduction
          in fair
          value as of June 30, 2006.
 
 **Regulatory
          Matters**
 
 Regulatory
          assets
          and liabilities are costs which have been authorized by the PPUC and the
          FERC
          for recovery from or credit to customers in future periods and, without
          such
          authorization, would have been charged or credited to income when incurred.
          Penelec’s net regulatory liabilities were approximately $135 million and
          $163 million as of June 30, 2006 and December 31, 2005,
          respectively, and are included under Noncurrent Liabilities on the Consolidated
          Balance Sheets.
  A February 2002 Commonwealth Court of Pennsylvania decision affirmed the
          June
          2001 PPUC decision regarding approval of the FirstEnergy/GPU merger, remanded
          the issues of quantification and allocation of merger savings to the PPUC
          and
          denied Met-Ed and Penelec the rate relief initially approved in the PPUC
          decision. On October 2, 2003, the PPUC issued an order concluding that
          the
          Commonwealth Court reversed the PPUC’s June 2001 order in its entirety. In
          accordance with the PPUC’s direction, Met-Ed and Penelec filed supplements to
          their tariffs that became effective in October 2003 and that reflected
          the CTC
          rates and shopping credits in effect prior to the June 2001 order.
 
 Met-Ed’s
          and
          Penelec’s combined portion of total net merger savings during 2001 - 2004 is
          estimated to be approximately $51 million. A procedural schedule was
          established by the ALJ on January 17, 2006 and the companies filed initial
          testimony on March 1, 2006. On May 4, 2006, the PPUC consolidated this
          proceeding with the April 10, 2006 comprehensive rate filing proceeding
          discussed below. Met-Ed and Penelec are unable to predict the outcome of
          this
          matter.
  165
  In
          an
          October 16, 2003 order, the PPUC approved September 30, 2004 as the
          date for Met-Ed's and Penelec's NUG trust fund refunds. The PPUC order
          also
          denied their accounting treatment request regarding the CTC rate/shopping
          credit
          swap by requiring Met-Ed and Penelec to treat the stipulated CTC rates
          that were
          in effect from January 1, 2002 on a retroactive basis. On October 22,
          2003, Met-Ed and Penelec filed an Objection with the Commonwealth Court
          asking
          that the Court reverse this PPUC finding; a Commonwealth Court judge
          subsequently denied their Objection on October 27, 2003 without
          explanation. On October 31, 2003, Met-Ed and Penelec filed an Application
          for Clarification of the Court order with the Commonwealth Court, a Petition
          for
          Review of the PPUC's October 2 and October 16, 2003 Orders, and an
          Application for Reargument, if the judge, in his clarification order, indicates
          that Met-Ed's and Penelec's Objection was intended to be denied on the
          merits.
          The Reargument Brief before the Commonwealth Court was filed on January 28,
          2005. Oral arguments were held on June 8, 2006. On July 19, 2006, the
          Commonwealth Court issued its decision affirming the PPUC’s prior orders.
          Although the decision denied the appeal of Met-Ed and Penelec, they had
          previously accounted for the treatment of costs required by the PPUC’s October
          2003 orders.
 
 On
          November 18,
          2004, the FERC issued an order eliminating the RTOR for transmission service
          between the MISO and PJM regions. The FERC also ordered the MISO, PJM and
          the
          transmission owners within MISO and PJM to submit compliance filings containing
          a SECA mechanism to recover lost RTOR revenues during a 16-month transition
          period from load serving entities. The FERC issued orders in 2005 setting
          the
          SECA for hearing. ATSI, JCP&L, Met-Ed, Penelec, and FES continue to be
          involved in the FERC hearings concerning the calculation and imposition
          of the
          SECA charges. The hearing was held in May 2006. Initial briefs were
          submitted on June 9, 2006, and reply briefs were filed on June 27, 2006.
          The 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 refund and hearing procedures. On
          June 30, 2005, the settling PJM transmission owners filed a request for
          rehearing of the May 31, 2005 order. On
          March 20, 2006, a settlement was filed with FERC in the formula rate
          proceeding that generally accepts the companies' formula rate proposal.
          The FERC
          issued an order approving this settlement on April 19, 2006. Hearings in
          the PJM rate design case concluded in April 2006. On July 13, 2006, an
          Initial
          Decision was issued by the ALJ. The ALJ adopted the Trial Staff’s position that
          the cost of all PJM transmission facilities should be recovered through
          a
          postage stamp rate. The ALJ recommended an April 1, 2006 effective date
          for this
          change in rate design. If the FERC accepts this recommendation, the transmission
          rate applicable to many load zones in PJM would increase. FirstEnergy believes
          that significant additional transmission revenues would have to be recovered
          from the JCP&L, Met-Ed and Penelec transmission zones within PJM. The
          Companies, as part of the Responsible Pricing Alliance, intend to submit
          a brief
          on exceptions within thirty days of the initial decision. Following submission
          of reply exceptions, the case is expected to be reviewed by the FERC with
          a
          decision anticipated in the fourth quarter of 2006.
 
 On
          January 12,
          2005, Met-Ed and Penelec filed, before the PPUC, a request for deferral
          of
          transmission-related costs beginning January 1, 2005. The OCA, OSBA, OTS,
          MEIUG, PICA, Allegheny Electric Cooperative and Pennsylvania Rural Electric
          Association all intervened in the case. Met-Ed and Penelec sought to consolidate
          this proceeding (and modified their request to provide deferral of 2006
          transmission-related costs only) with the comprehensive rate filing they
          made on
          April 10, 2006 as described below. On May 4, 2006, the PPUC approved
          the modified request. Accordingly, Penelec deferred approximately
          $12 million, representing transmission costs that were incurred from
          January 1, 2006 through June 30, 2006. On June 5, 2006, the OCA filed
          before the Commonwealth Court a petition for review of the PPUC’s approval of
          the deferral. On July 12, 2006, the Commonwealth Court granted the PPUC’s motion
          to quash the OCA’s appeal. The ratemaking treatment of the deferrals will be
          determined in the comprehensive rate filing proceeding discussed further
          below.
 
 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.
  166
  In lieu of allowing such termination to become effective as of December 31,
          2006, the parties agreed, pursuant to the Tolling Agreement, to amend the
          wholesale power sales agreement to provide as follows:
  1.
                    The
                      termination provisions of the wholesale power sales agreement
                      will be
                      tolled for one year until December 31, 2007, provided that during
                      such tolling period:
 
 a. FES
              will be
              permitted to terminate the wholesale power sales agreement at any time
              with
              sixty days written notice;
 b. Met-Ed
              and Penelec will procure through arrangements other than the wholesale
              power
              sales agreement beginning December 1, 2006 and ending December 31,
              2007, approximately 33% of the amounts of capacity and energy necessary
              to
              satisfy their PLR obligations for which Committed Resources (i.e.,
              non-utility
              generation under contract to Met-Ed and Penelec, Met-Ed- and Penelec-owned
              generating facilities, purchased power contracts and distributed generation)
              have not been obtained; and
 c. FES
              will not be obligated to supply additional quantities of capacity and
              energy in
              the event that a supplier of Committed Resources defaults on its supply
              agreement.
 
 2.
                    During
                      the
                      tolling period, FES will not act as an agent for Met-Ed or
                      Penelec in
                      procuring the services under 1.(b) above;
                      and
 
 3.
                    The
                        pricing provision of the wholesale power sales agreement
                        shall remain
                        unchanged provided Met-Ed and Penelec comply with the provisions
                        of the
                        Tolling
                      Agreement
                        and
                        any applicable provision of the wholesale power sales
                        agreement.
 In the event that FES elects not to terminate the wholesale power sales
              agreement effective midnight December 31, 2007, similar tolling agreements
              effective after December 31, 2007 are expected to be considered by FES for
              subsequent years if Met-Ed and Penelec procure through arrangements
              other than
              the wholesale power sales agreement approximately 64%, 83% and 95%
              of the
              additional amounts of capacity and energy necessary to satisfy their
              PLR
              obligations for 2008, 2009 and 2010, respectively, for which Committed
              Resources
              have not been obtained from the market.
 
 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.
 
 Penelec
          made a
          comprehensive rate filing with the PPUC on April 10, 2006 that addresses a
          number of transmission, distribution and supply issues. If Penelec's preferred
          approach involving accounting deferrals is approved, the filing would increase
          annual revenues by $157 million. That filing includes, among other things,
          a request to charge customers for an increasing amount of market-priced
          power
          procured through a CBP as the amount of supply provided under the existing
          FES
          agreement is phased out in accordance with the April 7, 2006 Tolling
          Agreement described above. Penelec also requested approval of the
          January 12, 2005 petition for the deferral of transmission-related costs
          discussed above, but only for those costs incurred during 2006. In this
          rate
          filing, Penelec also requested recovery of annual transmission and related
          costs
          incurred on or after January 1, 2007, plus the amortized portion of 2006
          costs over a ten-year period, along with applicable carrying charges, through
          an
          adjustable rider similar to that implemented in Ohio. The filing contemplates
          an
          increase in distribution rates for Penelec of $20 million annually. The
          PPUC suspended the effective date (June 10, 2006) of these rate changes for
          seven months after the filing as permitted under Pennsylvania law. If the
          PPUC adopts
          the overall positions taken in the intervenors’ testimony as filed, this would
          have a material adverse effect on the financial statements of FirstEnergy,
          Met-Ed and Penelec.Hearings are scheduled for late August 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.
  167
  **Environmental
          Matters** **
 
 Penelec
          accrues
          environmental liabilities when it concludes that it is probable that it
          has an
          obligation for such costs and can reasonably determine the amount of such
          costs.
          Unasserted claims are reflected in Penelec's determination of environmental
          liabilities and are accrued in the period that they are both probable and
          reasonably estimable.
 
 Penelec
          has been
          named a PRP at waste disposal sites, which may require cleanup under the
          Comprehensive Environmental Response, Compensation and Liability Act of
          1980.
          Allegations of disposal of hazardous substances at historical sites and
          the
          liability involved are often unsubstantiated and subject to dispute; however,
          federal law provides that all PRPs for a particular site are liable on
          a joint
          and several basis. Therefore, environmental liabilities that are considered
          probable have been recognized on the Consolidated Balance Sheet as of
          June 30, 2006, based on estimates of the total costs of cleanup, Penelec’s
          proportionate responsibility for such costs and the financial ability of
          other
          unaffiliated entities to pay.
 
 **Other
          Legal Proceedings**
 
 There
          are various
          lawsuits, claims (including claims for asbestos exposure) and proceedings
          related to Penelec’s normal business operations pending against Penelec. The
          other material items not otherwise discussed below are described in
          Note 10(C) to the consolidated financial statements.
 
 *Power
          Outages
          and Related Litigation*
  On August 14, 2003, various states and parts of southern Canada experienced
          widespread power outages. The outages affected approximately 1.4 million
          customers in FirstEnergy's service area. The U.S. - Canada Power System
          Outage
          Task Force’s final report in April 2004 on the outages concluded, among other
          things, that the problems leading to the outages began in FirstEnergy’s Ohio
          service area. Specifically,
          the
          final report concluded, among other things, that the initiation of the
          August 14, 2003 power outages resulted from an alleged failure of both
          FirstEnergy and ECAR to assess and understand perceived inadequacies within
          the
          FirstEnergy system; inadequate situational awareness of the developing
          conditions; and a perceived failure to adequately manage tree growth in
          certain
          transmission rights of way. The Task Force also concluded that there was
          a
          failure of the interconnected grid's reliability organizations (MISO and
          PJM) to
          provide effective real-time diagnostic support. The final report is publicly
          available through the Department of Energy’s Web site (www.doe.gov). FirstEnergy
          believes that the final report does not provide a complete and comprehensive
          picture of the conditions that contributed to the August 14, 2003 power
          outages and that it does not adequately address the underlying causes of
          the
          outages. FirstEnergy remains convinced that the outages cannot be explained
          by
          events on any one utility's system. The final report contained 46
“recommendations to prevent or minimize the scope of future blackouts.”
Forty-five of those recommendations related to broad industry or policy
          matters
          while one, including subparts, related to activities the Task Force recommended
          be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct
          the
          causes of the August 14, 2003 power outages. FirstEnergy implemented
          several initiatives, both prior to and since the August 14, 2003 power
          outages, which were independently verified by NERC as complete in 2004
          and were
          consistent with these and other recommendations and collectively enhance
          the
          reliability of its electric system. FirstEnergy’s implementation of these
          recommendations in 2004 included completion of the Task Force recommendations
          that were directed toward FirstEnergy. FirstEnergy is also proceeding with
          the
          implementation of the recommendations that were to be completed subsequent
          to
          2004 and will continue to periodically assess the FERC-ordered Reliability
          Study
          recommendations for forecasted 2009 system conditions, recognizing revised
          load
          forecasts and other changing system conditions which may impact the
          recommendations. Thus far, implementation of the recommendations has not
          required, nor is expected to require, substantial investment in new or
          material
          upgrades to existing equipment. The FERC or other applicable government
          agencies
          and reliability coordinators may, however, take a different view as to
          recommended enhancements or may recommend additional enhancements in the
          future
          as the result of adoption of mandatory reliability standards pursuant to
          the
          EPACT that could require additional material expenditures.
  168
  
 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.
          FirstEnergy's motion to dismiss the matter was denied on June 2, 2006.
          FirstEnergy has since filed an appeal, which is pending. A responsive pleading
          to this matter has been filed. Also, the complaint has been amended to
          include
          an additional party. No estimate of potential liability has been undertaken
          in
          this matter.
 
 FirstEnergy
          is
          vigorously defending these actions, but cannot predict the outcome of any
          of
          these proceedings or whether any further regulatory proceedings or legal
          actions
          may be initiated against the Companies. In particular, if FirstEnergy or
          its
          subsidiaries were ultimately determined to have legal liability in connection
          with these proceedings, it could have a material adverse effect on FirstEnergy's
          or its subsidiaries' financial condition, results of operations and cash
          flows.
 
 **New
          Accounting Standards and Interpretations**
 
 *FSP
          FIN 46(R)-6 - “Determining the Variability to Be Considered in Applying FASB
          interpretation No. 46(R)”*
 
 In
          April 2006, the
          FASB issued FSP FIN 46(R)-6 that addresses how a reporting enterprise should
          determine the variability to be considered in applying FASB interpretation
          No.
          46 (revised December 2003). FirstEnergy adopted FIN 46(R) in the first
          quarter
          of 2004, consolidating VIE’s when FirstEnergy or one of its subsidiaries is
          determined to be the VIE’s primary beneficiary. The variability that is
          considered in applying interpretation 46(R) affects the determination of
          (a)
          whether the entity is a VIE; (b) which interests are variable interests
          in the
          entity; and (c) which party, if any, is the primary beneficiary of the
          VIE. This
          FSP states that the variability to be considered shall be based on an analysis
          of the design of the entity, involving two steps:
 
 Step
                    1:
                Analyze
                    the
                    nature of the risks in the entityStep
                    2:
                Determine
                    the
                    purpose(s) for which the entity was created and determine the
                    variability
                    the entity is designed to create and pass along to its interest
                    holders.
 
 After
          determining
          the variability to consider, the reporting enterprise can determine which
          interests are designed to absorb that variability. The guidance in this
          FSP is
          applied prospectively to all entities (including newly created entities)
          with
          which that enterprise first becomes involved and to all entities previously
          required to be analyzed under interpretation 46(R) when a reconsideration
          event
          has occurred after July 1, 2006. Penelec does not expect this Statement
          to have
          a material impact on its financial statements.
 
 *FIN
          48 -
“Accounting for Uncertainty in Income Taxes - an interpretation of FASB
          Statement No. 109.”*
 
 In
          June 2006, the
          FASB issued FIN 48 which clarifies the accounting for uncertainty in income
          taxes recognized in an enterprise’s financial statements in accordance with FASB
          Statement No. 109, “Accounting for Income Taxes.” This interpretation prescribes
          a recognition threshold and measurement attribute for the financial statement
          recognition and measurement of a tax position taken or expected to be taken
          on a
          tax return. This interpretation also provides guidance on derecognition,
          classification, interest, penalties, accounting in interim periods, disclosure
          and transition. The evaluation of a tax position in accordance with this
          interpretation will be a two-step process. The first step will determine
          if it
          is more likely than not that a tax position will be sustained upon examination
          and should therefore be recognized. The second step will measure a tax
          position
          that meets the more likely than not recognition threshold to determine
          the
          amount of benefit to recognize in the financial statements. This interpretation
          is effective for fiscal years beginning after December 15, 2006. Penelec
          is
          currently evaluating the impact of this Statement.
 
 **SUBSEQUENT
          EVENTS**
 
 **Pennsylvania
          Law Change**
 
 On
          July 12, 2006,
          the Governor of Pennsylvania signed House Bill 859, which increases the
          net
          operating loss deduction allowed for the corporate net income tax from
          $2
          million to $3 million, or the greater of 12.5% of taxable income. As a
          result,
          Penelec expects to recognize a net operating loss benefit of $2.2 million
          (net
          of federal tax benefit) in the third quarter of 2006.
 
  169
  **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 June 30, 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.
  170
  ***PART
          II. OTHER INFORMATION***
 
 **ITEM
          1.**  **LEGAL
          PROCEEDINGS**
 
 Information
          required
          for Part II, Item 1 is incorporated by reference to the discussions in
          Notes 10
          and 11 of the Consolidated Financial Statements in Part I, Item 1 of this
          Form
          10-Q.
  **ITEM
          1A.**  **RISK
          FACTORS**
  See Item 1A RISK FACTORS in Part I of the Form 10-K for the year ended
          December
          31, 2005 for a discussion of the risk factors of FirstEnergy and the subsidiary
          registrants. For the quarter ended June 30, 2006, there have been no material
          changes to these risk factors.
 
 **ITEM
          2.**  **UNREGISTERED
          SALES OF EQUITY SECURITIES AND USE OF PROCEEDS**
 
 **(c)**  **FirstEnergy**
 
 The
          table below
          includes information on a monthly basis regarding purchases made by FirstEnergy
          of its common stock.
 
 **Period**April
                      1-30,
                  
                  
                  **May
                      1-31,**
                  
                  
                  **June
                      1-30,**
                  
                  
                  **Second****2006**
                  
                  
                  **2006**
                  
                  
                  **2006**
                  
                  
                  **Quarter**Total
                      Number
                      of Shares Purchased(a)
                  
                  
                  132,910
                  
                  
                  481,150
                  
                  
                  470,009
                  
                  
                  1,084,069Average
                      Price
                      Paid per Share
                  
                  $
                  49.82
                  
                  $
                  52.26
                  
                  $
                  53.10
                  
                  $
                  52.33Total
                      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)
                On
                    June 20, 2006, FirstEnergy Corp. announced that its Board of
                    Directors has authorized a share repurchase program for up to
                    12 million
                    shares of common stock. At management’s discretion, shares may be acquired
                    on the open market or through privately negotiated transactions,
                    subject
                    to market conditions and other factors. The Board’s authorization of the
                    repurchase program does not require FirstEnergy to purchase any
                    shares and
                    the program may be terminated at any
                    time.
 
 **ITEM
          4.**  **SUBMISSION
          OF MATTERS TO A VOTE OF SECURITY HOLDERS**
 
 (a)
                The
                    annual
                    meeting of FirstEnergy shareholders was held on May 16, 2006.
 
 (b)
                At
                    this
                    meeting, the following persons were elected to FirstEnergy's
                    Board of
                    Directors for one-year terms:
 
 **Number
                    of Votes****For**
                
                **Withheld**Anthony
                    J.
                    Alexander
                
                193,156,658
                
                
                90,938,042Dr.
                    Carol A.
                    Cartwright
                
                164,744,513
                
                
                119,350,187William
                    T.
                    Cottle
                
                183,961,100
                
                
                100,133,600Robert
                    B.
                    Heisler, Jr.
                
                268,681,345
                
                
                15,413,355Russell
                    W.
                    Maier
                
                186,309,666
                
                
                97,785,034George
                    M.
                    Smart
                
                183,516,902
                
                
                100,577,798Wes
                    M.
                    Taylor
                
                186,519,704
                
                
                97,574,996Jesse
                    T.
                    Williams, Sr.
                
                185,540,843
                
                
                98,553,857
 
 The
          term of office
          for the following Directors continued after the shareholders meeting and
          expires
          in 2007: Paul T. Addison, Ernest J. Novak, Jr., Catherine A. Rein and Robert
          C.
          Savage. The following Directors retired from the Board effective May 16,
          2006:
          Robert N. Pokelwaldt, Paul J. Powers and Dr. Patricia K. Woolf.
  171
  
 (c)  (i)  At
          this meeting, the
          appointment of PricewaterhouseCoopers LLP, an independent registered public
          accounting firm, as auditor for the year 2006 was ratified:
 
 **Number
                    of Votes****For**
                
                **Against**
                
                **Abstentions**278,799,686
                
                
                2,661,331
                
                
                2,633,683
 
 (ii)  At
          this meeting, a
          shareholder proposal recommending that the Board of Directors adopt simple
          majority shareholder voting and make it applicable to the greatest number
          of
          governance issues practicable was approved (approval required a favorable
          vote
          of a majority of the votes cast):
 
 **Number
                    of Votes****Broker****For**
                
                **Against**
                
                **Abstentions**
                
                **Non-Votes**184,910,522
                
                
                67,099,919
                
                
                4,832,226
                
                
                27,252,033
 
 Based
          on this
          result, the Board of Directors will further review this proposal
          and
          consider
 the
          appropriate
          steps to take in response.
 
 (iii)  At
          this meeting, a
          shareholder proposal urging the Board of Directors to seek shareholder
          approval
          of future severance agreements with senior executives that provide benefits
          in
          an amount exceeding 2.99 times the sum of the executives' base salary plus
          bonus
          was not approved (approval required a favorable vote of a majority of the
          votes
          cast):
  **Number
                    of Votes****Broker****For**
                
                **Against**
                
                **Abstentions**
                
                **Non-Votes**123,673,866
                
                
                128,388,870
                
                
                4,780,131
                
                
                27,251,833
 
 **ITEM
          6.**  **EXHIBITS**
 
 
 **Exhibit**
                  **Number****FirstEnergy**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.
  172
  
 **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.
  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.
  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.
 
  173
   **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.
 
 
 August
          7,
          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
 
  174