**THE
      CLEVELAND ELECTRIC****ILLUMINATING COMPANY**





**2005
      ANNUAL REPORT TO STOCKHOLDERS**











The
      Cleveland
      Electric Illuminating Company is a wholly owned electric utility operating
      subsidiary of FirstEnergy Corp. It engages in the distribution and sale of
      electric energy in an area of approximately 1,700 square miles in northeastern
      Ohio. It also engages in the sale, purchase and interchange of electric energy
      with other electric companies. The area it serves has a population of
      approximately 1.9 million.























**Contents**
            
            **Page**Glossary
                of
                Terms
            
            
            i-iiReport
                of
                Independent Registered Public Accounting Firm
            
            
            1Selected
                Financial Data
            
            
            2Management's
                Discussion and Analysis
            
            
            3-18Consolidated
                Statements of Income
            
            
            19Consolidated
                Balance Sheets
            
            
            20Consolidated
                Statements of Capitalization
            
            
            21Consolidated
                Statements of Common Stockholder's Equity
            
            
            22Consolidated
                Statements of Preferred Stock
            
            
            22Consolidated
                Statements of Cash Flows
            
            
            23Consolidated
                Statements of Taxes
            
            
            24Notes
                to
                Consolidated Financial Statements
            
            
            25-44











**GLOSSARY
      OF
      TERMS**





The
      following
      abbreviations and acronyms are used in this report to identify The Cleveland
      Electric Illuminating Company and its affiliates:





ATSI
            American
                Transmission Systems, Inc., owns and operates transmission
                facilitiesCEI
            The
                Cleveland
                Electric Illuminating Company, an Ohio electric utility operating
                subsidiaryCFC
            Centerior
                Funding Corporation, a wholly owned finance subsidiary of
                CEICompanies
            OE,
                CEI, TE,
                Penn, JCP&L, Met-Ed and 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
                facilitiesFirstEnergy
            FirstEnergy
                Corp., a public utility holding companyJCP&L
            Jersey
                Central
                Power & Light Company, an affiliated New Jersey electric
                utilityMet-Ed
            Metropolitan
                Edison Company, an affiliated Pennsylvania electric
                utilityNGC
            FirstEnergy
                Nuclear Generation Corp., owns nuclear generating
                facilitiesOE
            Ohio
                Edison
                Company, an affiliated Ohio electric utilityOhio
                Companies
            CEI,
                OE and
                TEPenelec
            Pennsylvania
                Electric Company, an affiliated Pennsylvania electric
                utilityPenn
            Pennsylvania
                Power Company, an affiliated Pennsylvania electric
                utilityShippingport
            Shippingport
                Capital Trust, a special purpose entity created by CEI and TE in
                1997TE
            The
                Toledo
                Edison Company, an affiliated Ohio electric utilityThe
                following
                abbreviations and acronyms are used to identify frequently used terms
                in
                this report:AOCL
            Accumulated
                Other Comprehensive LossAPB
            Accounting
                Principles BoardAPB
                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 ObligationCAT
            Commercial
                Activity TaxCO2
            Carbon
                DioxideCTC
            Competitive
                Transition ChargeECAR
            East
                Central
                Area Reliability AgreementEITF
            Emerging
                Issues Task ForceEITF
                03-1
            EITF
                Issue No.
                03-1, "The Meaning of Other-Than-Temporary and Its Application to
                Certain
              Investments"EITF
                04-13
            EITF
                Issue No.
                04-13, "Accounting for Purchases and Sales of Inventory with the
                Same
                CounterpartyEPA
            Environmental
                Protection AgencyEPACT
            Energy
                Policy
                Act of 2005FASB
            Financial
                Accounting Standards BoardFERC
            Federal
                Energy
                Regulatory CommissionFIN
                46R
            FASB
                Interpretation No. 46 (revised December 2003), "Consolidation of
                Variable
                Interest Entities"FIN
                47
            FASB
                Interpretation 47, "Accounting for Conditional Asset Retirement
                Obligations - an interpretation of FASBStatement
                No.
                143"FMB
            First
                Mortgage
                BondsFSP
            FASB
                Staff
                PositionFSP
                106-1
            FASB
                Staff
                Position No.106-1, "Accounting and Disclosure Requirements Related
                to the
                Medicare
              Prescription
                Drug, Improvement and Modernization Act of 2003"FSP
                106-2
            FASB
                Staff
                Position No.106-2, "Accounting and Disclosure Requirements Related
                to
                the
              Medicare
                Prescription Drug, Improvement and Modernization Act of
                2003"FSP
                115-1 and
              FAS
                124-1
            FASB
                Staff
                Position No. 115-1 and FAS 124-1, "The Meaning of Other-Than-Temporary
                Impairment and its Application to Certain Investments"GAAP
            Accounting
                Principles Generally Accepted in the United StatesGCAF
            Generation
                Charge Adjustment FactorIRS
            Internal
                Revenue ServiceKWH
            Kilowatt-hoursLOC
            Lettter
              of
              CreditMedicare
                Act
            Medicare
                Prescription Drug, Improvement and Modernization Act of
                2003MISO
            Midwest
                Independent Transmission System Operator, Inc.Moody’s
            Moody’s
                Investors ServiceMSG
            Market
                Support
                Generation





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


MW
            MegawattsNAAQS
            National
                Ambient Air Quality StandardsNERC
            North
                American
                Electric Reliability CouncilNOAC
            Northwest
                Ohio
                Aggregation CoalitionNOX
            Nitrogen
                OxideNRC
            Nuclear
                Regulatory CommissionOCC
            Ohio
                Consumers' CounselOCI
            Other
                Comprehensive IncomeOPEB
            Other
                Post-Employment BenefitsPJM
            PJM
                Interconnection L. L. C.PLR
            Provider
                of
                Last ResortPRP
            Potentially
                Responsible PartyPUCO
            Public
                Utilities Commission of OhioPUHCA
            Public
                Utility
                Holding Company ActRCP
            Rate
                Certainty
                PlanRFP
            Request
              for
              ProposalRSP
            Rate
                Stabilization PlanRTC
            Regulatory
                Transition ChargeS&P
            Standard
&
                Poor’s Ratings ServiceSEC
            United
                States
                Securities and Exchange CommissionSFAC
            Statement
                of
                Financial Accounting ConceptsSFAC
                7
            SFAC
                No. 7,
                "Using Cash Flow Information and Present Value in Accounting
                Measurements"SFAS
            Statement
                of
                Financial Accounting StandardsSFAS
                71
            SFAS
                No. 71,
                "Accounting for the Effects of Certain Types of
                Regulation"SFAS
                87
            SFAS
                No. 87,
                "Employers' Accounting for Pensions"SFAS
                101
            SFAS
                No. 101,
                "Accounting for Discontinuation of Application of SFAS
                71"SFAS
                106
            SFAS
                No. 106,
                "Employers' Accounting for Postretirement Benefits Other Than
                Pensions"SFAS
                115
            SFAS
                No. 115,
                "Accounting for Certain Investments in Debt and Equity
                Securities"SFAS
                140
            SFAS
                No. 140,
                "Accounting for Transfers and Servicing of Financial Assets
                and
              Extinguishment
                of Liabilities"SFAS
                142
            SFAS
                No. 142,
                "Goodwill and Other Intangible Assets"SFAS
                143
            SFAS
                No. 143,
                "Accounting for Asset Retirement Obligations"SFAS
                144
            SFAS
                No. 144,
                "Accounting for the Impairment or Disposal of Long-Lived
                Assets"SFAS
                150
            SFAS
                No. 150,
                "Accounting for Certain Financial Instruments with Characteristics
                of Both
                Liabilities and Equity"SFAS
                151
            SFAS
                No. 151,
                "Inventory Costs - an amendment of ARB No. 43, Chapter
                4"SFAS
                153
            SFAS
                No. 153,
                "Exchanges of Nonmonetary Assets - an amendment of APB Opinion No.
                29"SFAS
                154
            SFAS
                No. 154,
                "Accounting Changes and Error Corrections - a replacement of APB
                Opinion
                No. 20 and FASB Statement No. 3"SO2
            Sulfur
                DioxideVIE
            Variable
                Interest Entity











ii








**Report
      of
      Independent Registered Public Accounting Firm**








To
      the Stockholder
      and Board of Directors of


The
      Cleveland
      Electric Illuminating Company:








In
      our opinion, the
      accompanying consolidated balance sheets and the related consolidated statements
      of income, capitalization, common stockholder’s equity, preferred stock, cash
      flows and taxes present fairly, in all material respects, the financial position
      of The Cleveland Electric Illuminating Company and its subsidiaries at
      December 31, 2005 and 2004, and the results of their operations and their
      cash flows for each of the three years in the period ended December 31,
      2005 in conformity with accounting principles generally accepted in the United
      States of America. These financial statements are the responsibility of the
      Company’s management. Our responsibility is to express an opinion on these
      financial statements based on our audits. We conducted our audits of these
      statements in accordance with the standards of the Public Company Accounting
      Oversight Board (United States). Those standards require that we plan and
      perform the audit to obtain reasonable assurance about whether the financial
      statements are free of material misstatement. An audit includes examining,
      on a
      test basis, evidence supporting the amounts and disclosures in the financial
      statements, assessing the accounting principles used and significant estimates
      made by management, and evaluating the overall financial statement presentation.
      We believe that our audits provide a reasonable basis for our
      opinion.





As
      discussed in
      Note 2(G) and Note 11 to the consolidated financial statements, the
      Company changed 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 6 to the consolidated financial statements, the Company changed its
      method of accounting for the consolidation of variable interest entities as
      of
      December 31, 2003.











PricewaterhouseCoopers
      LLP


Cleveland,
      Ohio


February
      27,
      2006


1


The
      following
      selected financial data should be read in conjunction with, and is qualified
      in
      its entirety by reference to, the sections entitled “Management’s Discussion and
      Analysis of Results of Operations and Financial Condition” and with our
      consolidated financial statements and the “Notes to Consolidated Financial
      Statements.” Our Consolidated Statements of Income are not necessarily
      indicative of future conditions or results of operations.





**THE
                  CLEVELAND ELECTRIC ILLUMINATING COMPANY****SELECTED
                  FINANCIAL DATA****2005**
              
              **2004**
              
              **2003**
              
              **2002**
              
              **2001*****(Dollars
                  in thousands)*****GENERAL
                  FINANCIAL INFORMATION:**Operating
                  Revenues
              
              $
              1,868,161
              
              $
              1,808,485
              
              $
              1,719,739
              
              $
              1,843,671
              
              $
              2,064,622Operating
                  Income
              
              $
              308,852
              
              $
              327,909
              
              $
              255,615
              
              $
              306,152
              
              $
              354,422Income
                  Before
                  Cumulative Effectof
                  Accounting
                  Changes
              
              $
              231,058
              
              $
              236,531
              
              $
              197,033
              
              $
              136,962
              
              $
              177,905Net
                  Income
              
              $
              227,334
              
              $
              236,531
              
              $
              239,411
              
              $
              136,952
              
              $
              177,905Earnings
                  on
                  Common Stock
              
              $
              224,416
              
              $
              229,523
              
              $
              231,885
              
              $
              121,262
              
              $
              153,067Total
                  Assets
              
              $
              6,101,670
              
              $
              6,675,377
              
              $
              6,758,501
              
              $
              6,500,238
              
              $
              6,515,968**CAPITALIZATION
                  AS OF DECEMBER 31:**Common
                  Stockholder’s Equity
              
              $
              1,942,074
              
              $
              1,853,561
              
              $
              1,778,827
              
              $
              1,200,001
              
              $
              1,082,041Preferred
                  Stock-Not
                  Subject to Mandatory
                  Redemption
              
              
              -
              
              
              96,404
              
              
              96,404
              
              
              96,404
              
              
              141,475Subject
                  to
                  Mandatory Redemption
              
              
              -
              
              
              -
              
              
              -
              
              
              105,021
              
              
              106,288Long-Term
                  Debt
                  and Other Long-Term Obligations
              
              
              1,939,300
              
              
              1,970,117
              
              
              1,884,643
              
              
              1,975,001
              
              
              2,156,322Total
                  Capitalization
              
              $
              3,881,374
              
              $
              3,920,082
              
              $
              3,759,874
              
              $
              3,376,427
              
              $
              3,486,126**CAPITALIZATION
                  RATIOS:**Common
                  Stockholder’s Equity
              
              
              50.0
              %
              
              47.3
              %
              
              47.3
              %
              
              35.5
              %
              
              31.0
              %Preferred
                  Stock-Not
                  Subject to
                  Mandatory Redemption
              
              
              -
              
              
              2.5
              
              
              2.6
              
              
              2.9
              
              
              4.1Subject
                  to
                  Mandatory Redemption
              
              
              -
              
              
              -
              
              
              -
              
              
              3.1
              
              
              3.0Long-Term
                  Debt
                  and Other Long-Term Obligations
              
              
              50.0
              
              
              50.2
              
              
              50.1
              
              
              58.5
              
              
              61.9Total
                  Capitalization
              
              
              100.0
              %
              
              100.0
              %
              
              100.0
              %
              
              100.0
              %
              
              100.0
              %**DISTRIBUTION
                  KWH DELIVERIES (Millions):**Residential
              
              
              5,699
              
              
              5,264
              
              
              5,216
              
              
              5,370
              
              
              5,061Commercial
              
              
              4,998
              
              
              4,817
              
              
              4,690
              
              
              4,628
              
              
              4,907Industrial
              
              
              9,041
              
              
              9,006
              
              
              8,908
              
              
              8,921
              
              
              9,593Other
              
              
              172
              
              
              162
              
              
              169
              
              
              167
              
              
              166Total
              
              
              19,910
              
              
              19,249
              
              
              18,983
              
              
              19,086
              
              
              19,727**CUSTOMERS
                  SERVED:**Residential
              
              
              675,071
              
              
              674,292
              
              
              669,337
              
              
              677,095
              
              
              673,852Commercial
              
              
              85,033
              
              
              81,093
              
              
              80,596
              
              
              71,893
              
              
              70,636Industrial
              
              
              2,304
              
              
              2,211
              
              
              2,318
              
              
              4,725
              
              
              4,783Other
              
              
              295
              
              
              293
              
              
              286
              
              
              289
              
              
              292Total
              
              
              762,703
              
              
              757,889
              
              
              752,537
              
              
              754,002
              
              
              749,563**Number
                  of Employees**
              
              
              949
              
              
              905
              
              
              949
              
              
              974
              
              
              1,025








2


**THE
      CLEVELAND ELECTRIC ILLUMINATING COMPANY**





**MANAGEMENT’S
      DISCUSSION AND**


**ANALYSIS
      OF
      RESULTS OF OPERATIONS**


**AND
      FINANCIAL CONDITION**








***Forward-looking
      Statements.*** *This
      discussion
      includes forward-looking statements based on information currently available
      to
      management. Such statements are subject to certain risks and uncertainties.
      These statements typically contain, but are not limited to, the terms
      "anticipate," "potential," "expect," "believe," "estimate" and similar words.
      Actual results may differ materially due to the speed and nature of increased
      competition and deregulation in the electric utility industry, economic or
      weather conditions affecting future sales and margins, changes in markets for
      energy services, changing energy and commodity market prices, replacement power
      costs being higher than anticipated or inadequately hedged, the continued
      ability of our regulated utilities to collect transition and other charges
      or to
      recover increased transmission costs, maintenance costs being higher than
      anticipated, legislative and regulatory changes (including revised environmental
      requirements), the repeal of PUHCA and the legal and regulatory changes
      resulting from the implementation of the EPACT, the uncertainty of the timing
      and amounts of the capital expenditures (including that such amounts could
      be
      higher than anticipated) or levels of emission reductions related to the
      settlement agreement resolving the New Source Review litigation, adverse
      regulatory or legal decisions and outcomes (including, but not limited to,
      the
      revocation of necessary licenses or operating permits, fines or other
      enforcement actions and remedies) of governmental investigations and oversight,
      including by the Securities and Exchange Commission, the United States
      Attorney's Office, the Nuclear Regulatory Commission and the Public Utilities
      Commission of Ohio as disclosed in our Securities and Exchange Commission
      filings, the continuing availability and operation of generating units, the
      ability of generating units to continue to operate at, or near full capacity,
      our inability to accomplish or realize anticipated benefits from strategic
      goals
      (including employee workforce factors), the anticipated benefits from our
      voluntary pension plan contributions, our ability to improve electric commodity
      margins and to experience growth in the distribution business, our ability
      to
      access the public securities and other capital markets and the cost of such
      capital, the outcome, cost and other effects of present and potential legal
      and
      administrative proceedings and claims related to the August 14, 2003
      regional power outage, the risks and other factors discussed from time to time
      in our Securities and Exchange Commission filings, and other similar factors.
      Also, a credit rating should not be viewed as a recommendation to buy, sell
      or
      hold securities and may be revised or withdrawn by a rating agency at any time.
      We expressly disclaim any current intention to update any forward-looking
      statements contained herein as a result of new information, future events,
      or
      otherwise.*





**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
      our leasehold interests in certain of the plants that are currently subject
      to
      sale and leaseback arrangements with non-affiliates.





On
      October 24,
      2005, we completed the intra-system transfer of our ownership interests in
      the
      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, we completed the intra-system transfer of our 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 are
      expected to affect our near-term future results with reductions in revenues
      and
      expenses. Revenues will be reduced due to the termination of the sale of our
      nuclear-generated KWH and the lease of our non-nuclear generation assets
      arrangements with FES. Our expenses will be 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. We will
      retain a fossil generation KWH sales arrangement and the portion of expenses
      related to our retained leasehold interests in the Bruce Mansfield Plant. In
      addition, we will receive interest income from associated company notes
      receivable from FGCO and NGC for the transfer of our generation net assets.
      FES
      will continue to provide our PLR requirements under revised purchased power
      arrangements for a three-year period beginning January 1, 2006 (see Regulatory
      Matters).




3


**Results
      of
      Operations**





Earnings
      on common
      stock in 2005 decreased to $224 million
      from
      $230 million in 2004. Earnings on common stock in 2005 included an
      after-tax loss of $4 million from the cumulative effect of an accounting
      change due to the adoption of FIN 47. The $5 million decrease in
      income before the cumulative effect in 2005 resulted principally from higher
      nuclear and other operating costs and higher fuel and purchased power costs,
      partially offset by higher operating revenues and other income. Increased
      nuclear operating costs in 2005 compared to 2004 were due to an inspection
      outage at Davis-Besse and two nuclear refueling outages in 2005.





Earnings
      on common
      stock in 2004 decreased to $230 million from $232 million in 2003.
      Earnings on common stock in 2003 included an after-tax gain of $42 million
      from the cumulative effect of an accounting change due to the adoption of
      SFAS 143. Income before the cumulative effect increased to
      $237 million in 2004 from $197 million in 2003. This increase resulted
      principally from higher operating revenues, lower nuclear operating costs and
      reduced interest charges. These factors were partially offset by higher fuel
      and
      purchased power costs; depreciation and amortization charges and the absence
      of
      a 2003 gain representing net proceeds from the settlement of our claim against
      NRG relating to the terminated sale of three of our fossil power plants (see
      Note 7). Operating revenues were higher in 2004 due to significant
      increases in sales to FES. Lower nuclear operating costs in 2004 compared with
      2003, were due to reduced incremental maintenance costs associated with the
      Davis-Besse extended outage and the absence of nuclear outages at Beaver Valley
      Unit 2 and the Perry Plant in 2004. Lower net interest charges in 2004,
      compared with 2003, were primarily due to debt redemptions and refinancing
      activities.





*Operating
      Revenues*





Operating
      revenues
      increased by $60 million or 3.3% in 2005 compared with 2004. Higher
      revenues resulted principally from increased generation sales revenue from
      franchise customers of $33 million and a $33 million increase in
      revenues from distribution deliveries. Under the Ohio transition plan, we
      provided incentives to customers to encourage switching to alternative energy
      providers (shopping) - $7 million of additional credits were provided to
      customers in 2005 compared with 2004. These revenue reductions are deferred
      for
      future recovery under our transition plan and do not affect current period
      earnings (see Note 2(A)).





An
      increase in
      retail generation revenues to residential and commercial customers of
      $11 million and $5 million, respectively, in 2005 reflected higher
      generation KWH sales due to decreases in shopping by residential and commercial
      customers of 6.0 percentage points and 0.6 percentage point, respectively.
      A
      $17 million increase in the industrial sector was primarily due to higher
      unit prices partially offset by lower KWH sales of 0.6% which resulted from
      a
      slight increase in shopping. Wholesale sales revenue increased by
      $1 million due to a $26 million increase (28.5% KWH increase) in MSG
      sales to unaffiliated wholesale customers partially offset by a $25 million
      decrease in sales (5.6% KWH decrease) to FES.





Revenues
      from
      distribut ion
      throughput
      increased by $33 million in 2005 compared with 2004, as total distribution
      deliveries increased by 3.4% in 2005. The increase in revenues was primarily
      due
      to higher distribution deliveries to residential and commercial customers,
      in
      part due to warmer summer temperatures, partially offset by lower unit prices
      in
      both sectors. Industrial revenues were down slightly as lower unit prices were
      partially offset by higher distribution deliveries.





Oper ating
      revenues
      increased by $89 million or 5.2% in 2004 compared with 2003. Higher
      revenues resulted principally from a $136 million (44.2%) increase in
      wholesale sales (primarily to FES) due to increased nuclear generation available
      for sale which was partially offset by reduced generation sales revenue from
      franchise customers of $20 million. The reduction in retail generation
      revenues (residential - $9 million and commercial - $18 million) in
      2004 reflected an increase in shopping by residential and commercial customers
      of 5.5 percentage points and 8.2 percentage points, respectively. Reductions
      in
      residential and commercial revenues were partially offset by an $8 million
      increase in industrial retail generation revenues resulting from higher KWH
      sales (4.6%) to industrial customers due in part to a 2.7 percentage point
      reduction in shopping.





Revenues
      from
      distribution throughput decreased by $14 million in 2004 compared with
      2003, even though total distribution deliveries increased by 1.4% in 2004.
      An
      improving economy increased distribution deliveries to commercial and industrial
      customers in 2004; however, lower unit prices in all customer sectors in 2004
      more than offset the effect of higher distribution deliveries to residential
      and
      industrial customers and partially offset higher sales to the commercial sector.
      Revenues were further reduced due to $5 million of additional shopping
      incentive credits to customers in 2004 compared with 2003.




4


Changes
      in electric
      generation sales and distribution deliveries in 2005 and 2004, compared to
      the
      prior year, are summarized in the following table:





**Changes
                in KWH Sales**
            
            **2005**
            
            **2004****Increase
                (Decrease)**Electric
                Generation:Retail
            
            
            4.9
            %
            
            (2.6
            )%Wholesale
            
            
            (2.7
            )%
            
            44.2
            %**Total
                Electric Generation Sales**
            
            
            0.5
            %
            
            20.4
            %Distribution
                Deliveries:Residential
            
            
            8.3
            %
            
            0.9
            %Commercial
            
            
            3.8
            %
            
            2.7
            %Industrial
            
            
            0.4
            %
            
            1.1
            %**Total
                Distribution Deliveries**
            
            
            3.4
            %
            
            1.4
            %





*Operating
      Expenses and Taxes*





Total
      operating
      expenses and taxes increased by $79 million
      in
      2005 and $17 million in 2004 from the prior year. The following table
      presents changes from the prior year by expense category.





**Operating
                Expenses and Taxes - Changes**
            
            **2005**
            
            **2004****Increase
                (Decrease)**
            
            ***(In
                millions)***Fuel
                costs
            
            $
            8
            
            $
            23Purchased
                power costs
            
            
            14
            
            
            5Nuclear
                operating costs
            
            
            26
            
            
            (124
            )Other
                operating costs
            
            
            29
            
            
            36Provision
                for
                depreciation
            
            
            (4
            )
            
            7Amortization
                of regulatory assets
            
            
            31
            
            
            30Deferral
                of
                new regulatory assets
            
            
            (46
            )
            
            (24
            )General
                taxes
            
            
            6
            
            
            10Income
                taxes
            
            
            15
            
            
            54**Total
                operating expenses and taxes**
            
            $
            79
            
            $
            17





Higher
      fuel costs in
      2005 compared to 2004 were primarily due to increased fossil fuel expenses
      associated with higher fossil generation levels. Higher purchased power costs
      in
      2005 compared to 2004 reflected higher KWH purchases, partially offset by lower
      unit costs. Higher nuclear operating costs in 2005 compared with 2004, were
      due
      to the 2005 nuclear refueling and maintenance outages at the Perry Plant, the
      nuclear refueling outage at Beaver Valley Unit 2 (these units did not
      experience outages in 2004) and a scheduled 23-day mid-cycle inspection outage
      at the Davis-Besse nuclear plant. Higher other operating costs were primarily
      due to transmission expenses related to MISO Day 2 transactions that began
      on April 1, 2005.





Higher
      fuel costs in
      2004 compared to 2003 resulted principally from increased nuclear generation.
      Higher purchased power costs in 2004 reflected increased unit costs and KWH
      purchased. The decrease in nuclear operating costs for 2004 compared to 2003
      was
      due to reduced incremental costs associated with the Davis-Besse extended outage
      and work performed during the refueling outages at the Perry Plant and Beaver
      Valley Unit 2 in 2003. Other operating costs increased in 2004, in part
      from higher employee benefit costs.





The
      decrease in
      depreciation in 2005 compared to 2004 was primarily due to the non-nuclear
      intra-system generation transfer that occurred on October 24, 2005 (see
      Note 14). The increase in depreciation in 2004 compared to 2003 reflected a
      higher level of depreciable property in 2004. Higher amortization of regulatory
      assets in 2005 and 2004 as compared to the prior year was primarily due to
      increased amortization of transition regulatory assets being recovered under
      the
      RSP. Increases in the deferral of regulatory assets in 2005 from 2004 were
      primarily a result of higher shopping incentive deferrals ($7 million) and
      associated interest ($9 million), and the PUCO-approved MISO cost deferrals
      ($29 million) and associated interest ($1 million). Increases in the
      deferral of regulatory assets in 2004 from 2003 were primarily a result of
      higher shopping incentive deferrals ($5 million) and associated interest
      ($17 million).





General
      taxes
      increased $6 million in 2005 primarily due to higher property taxes.
      General taxes increased $10 million in 2004 primarily due to the absence in
      2004 of settled property tax claims in 2003.




Income
      taxes increased $15 million in 2005 primarily due to a reserve for
      potential  federal  income tax audit adjustments




5


On
      June 30,
      2005, tax legislation was enacted in the State of Ohio that created a new CAT
      tax, which is based on qualifying “taxable gross receipts” and does not consider
      any expenses or costs incurred to generate such receipts, except for items
      such
      as cash discounts, returns and allowances, and bad debts. The CAT tax was
      effective July 1, 2005, and replaces the Ohio income-based franchise tax
      and the Ohio personal property tax. The CAT tax is phased-in while the current
      income-based franchise tax is phased-out over a five-year period at a rate
      of
      20% annually, beginning with the year ended 2005, and the personal property
      tax
      is phased-out over a four-year period at a rate of approximately 25% annually,
      beginning with the year ended 2005. During the phase-out period the Ohio
      income-based franchise tax will be computed consistent with the prior tax law,
      except that the tax liability as computed will be multiplied by 4/5 in 2005;
      3/5
      in 2006; 2/5 in 2007 and 1/5 in 2008, therefore eliminating the current
      income-based franchise tax over a five-year period. As a result of the new
      tax
      structure, all net deferred tax benefits that were not expected to reverse
      during the five-year phase-in period were written-off as of June 30, 2005. The
      impact on income taxes associated with the required adjustment to net deferred
      taxes for 2005 was an additional tax expense of approximately $4 million,
      which was partially offset by the initial phase-out of the Ohio income-based
      franchise tax, which reduced income taxes by approximately $5 million in
      2005.





*Other
      Income*





Other
      income
      increased by $10 million
      in 2005,
      primarily due to higher realized gains on nuclear decommissioning trust
      investments. Other income decreased by $55 million in 2004, principally due
      to a $131 million pre-tax NRG settlement (see Note 7) recognized in 2003,
      partially offset by interest income from Shippingport, which was consolidated
      into CEI as of December 31, 2003.





*Net
      Interest
      Charges*





Net
      interest charges
      continued to trend lower, decreasing by $4 million in 2005 and by
      $22 million in 2004, due to our debt paydown program. Long-term debt
      interest was lower due to the redemptions of $2 million and refinancing of
      $143 million of pollution control notes during 2005.





*Cumulative
      Effect of Accounting Changes*





Results
      in 2005
      include an after-tax charge of $4 million recorded upon the adoption of
      FIN 47 in December 2005. We identified applicable legal obligations as
      defined under the new standard at our retired generating units, substation
      control rooms, service center buildings, line shops and office buildings,
      identifying asbestos as the primary conditional ARO. We recorded a conditional
      ARO liability of $7 million (including accumulated accretion for the period
      from the date the liability was incurred to the date of adoption), an asset
      retirement cost of $2 million (recorded as part of the carrying amount of
      the related long-lived asset), and accumulated depreciation of $2 million.
      W e
      charged regulatory liabilities for $1 million upon adoption of FIN 47
      for the transition amounts related to establishing the ARO for asbestos removal
      from substation control rooms and service center buildings. The remaining
      cumulative effect adjustment for unrecognized depreciation and accretion of
      $6 million was charged to income ($4 million, net of tax) for the year
      ended December 31, 2005.





Upon
      adoption of
      SFAS 143 in the first quarter of 2003, we recorded an after-tax gain to net
      income of $42 million. The cumulative effect adjustment for unrecognized
      depreciation and accretion, offset by the reduction in the existing
      decommissioning liabilities and ceasing the accounting practice of depreciating
      non-regulated generation assets using a cost of removal component, was a
      $73 million increase to income, or $42 million net of income taxes.





*Preferred
      Stock
      Dividend Requirements*





Preferred
      stock
      dividend requirements decreased by $4 million in 2005 from 2004 principally
      due to optional preferred stock redemptions of $100 million in 2005. There
      is no outstanding preferred stock as of December 31, 2005.





**Capital
      Resources and Liquidity**





Our
      cash
      requirements in 2005 for operating expenses, construction expenditures,
      scheduled debt maturities and preferred stock redemptions were met without
      increasing our net debt and preferred stock outstanding. During 2006, we expect
      to meet our contractual obligations with cash from operations. Thereafter,
      we
      expect to use a combination of cash from operations and funds from the capital
      markets.





*Changes
      in Cash
      Position*





As
      of
      December 31, 2005, we had $207,000 of cash and cash equivalents, compared
      with $197,000 as of December 31, 2004. The major sources of changes in
      these balances are summarized below.






6


*Cash
      Flows from
      Operating Activities*





Our
      net cash
      provided from operating activities for 2005 compared with 2004 and 2003 was
      as
      follows:





**Operating
                Cash Flows**
            
            **2005**
            
            **2004**
            
            **2003*****(In
                millions)***Cash
                earnings(1)
            
            $
            424
            
            $
            443
            
            $
            309Pension
                trust
                contribution(2)
            
            
            (63
            )
            
            (19
            )
            
            -Working
                capital and other
            
            
            (213
            )
            
            (202
            )
            
            2Net
                cash
                provided from operating activities
            
            $
            148
            
            $
            222
            
            $
            311





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


(2) Pension
      trust
      contributions in 2005 and 2004 are net of $30 million and $13 million
      of income tax benefits, respectively.





Cash
      earnings (in
      the table above) are not a measure of performance calculated in accordance
      with
      GAAP. We believe that cash earnings are a useful financial measure because
      it
      provides investors and management with an additional means of evaluating our
      cash-based operating performance. The following table reconciles cash earnings
      with net income.








**Reconciliation
                of Cash Earnings**
            
            **2005**
            
            **2004**
            
            **2003*****(In
                millions)***Net
                Income
                (GAAP)
            
            $
            227
            
            $
            237
            
            $
            239Non-Cash
                Charges (Credits):Provision
                for
                depreciation
            
            
            128
            
            
            132
            
            
            125Amortization
                of regulatory assets
            
            
            227
            
            
            196
            
            
            166Deferral
                of
                new regulatory assets
            
            
            (163
            )
            
            (117
            )
            
            (93
            )Nuclear
                fuel
                and capital lease amortization
            
            
            26
            
            
            28
            
            
            18Amortization
                of electric service obligation
            
            
            (14
            )
            
            (18
            )
            
            (16
            )Deferred
                rents
                and lease market valuation liability
            
            
            (68
            )
            
            (56
            )
            
            (78
            )Deferred
                income taxes and investment tax credits, net*
            
            
            42
            
            
            26
            
            
            (9
            )Accrued
                compensation and retirement benefits
            
            
            5
            
            
            15
            
            
            (1
            )Cumulative
                effect of accounting changes
            
            
            4
            
            
            -
            
            
            (42
            )Tax
                refund
                related to pre-merger period
            
            
            10
            
            
            -
            
            
            -Cash
                earnings
                (Non-GAAP)
            
            $
            424
            
            $
            443
            
            $
            309





*Excludes
      $13 million of deferred tax benefits from pension contributions in
      2004.





Net
      cash provided
      from operating activities decreased $74 million in 2005 compared to 2004 as
      a result of a $44 million increase in after-tax voluntary pension trust
      contributions, a $19 million decrease in cash earnings for the reasons
      described under "Results of Operations" and a $11 million decrease from
      working capital and other cash flows. The decrease from working capital and
      other cash flows was principally due to a decrease in cash provided from the
      settlement of receivables of $141 million which was partially offset by
      increases in cash of $65 million from reduced tax payments and
      $68 million of funds received in 2005 for prepaid electric service (under a
      three-year Energy for Education Program with the Ohio Schools Council). Net
      cash
      provided from operating activities decreased $89 million in 2004 compared
      to 2003 as a result of a $204 million decrease from changes from working
      capital and other cash flows and the $19 million after-tax voluntary
      pension trust contribution, in 2004, partially offset by a $134 million
      increase in cash earnings for the reasons described under "Results of
      Operations". The decrease from working capital and other cash flows was
      principally due to a $149 million increase in tax payments partially offset
      by a $55 million increase in cash from the settlement of accounts
      receivable.






7


*Cash
      Flows from
      Financing Activities*





In
      2005, 2004 and
      2003, net cash used for financing activities was $71 million,
      $98 million and $198 million, respectively, primarily reflecting the
      new issues and redemptions shown below.





**Securities
                Issued or Redeemed**
            
            **2005**
            
            **2004**
            
            **2003*****(In
                millions)******New
                Issues:***Pollution
                Control Notes
            
            $
            141
            
            $
            125
            
            $
            -Unsecured
                Notes
            
            
            -
            
            
            -
            
            
            297***Redemptions:***FMB
            
            $
            -
            
            $
            -
            
            $
            550Pollution
                Control Notes
            
            
            147
            
            
            46
            
            
            112Secured
                Notes
            
            
            -
            
            
            288
            
            
            15Preferred
                Stock
            
            
            102
            
            
            1
            
            
            1Other
            
            
            1
            
            
            1
            
            
            -$
            250
            
            $
            336
            
            $
            678Short-term
                borrowings, net
            
            $
            156
            
            $
            290
            
            $
            (109
            )





Net
      cash used for
      financ ing
      activities
      decreased by $27 million in 2005 compared to 2004. The decrease resulted
      from a $75 million equity contribution from FirstEnergy, partially offset
      by a $21 million increase in common stock dividend payments to FirstEnergy
      and an increase in net debt redemptions shown above.





We
      had $207,000 of
      cash and temporary investments and approximately $352 million
      of short-term indebtedness as of December 31, 2005. We have obtained
      authorization from the PUCO to incur short-term debt of up to $500 million
      (including through available bank facilities and the utility money pool
      described below). In
      addition, we have
      $200 million ($60 million unused as of December 31, 2005) of
      accounts receivable financing facilities from CFC, our wholly owned subsidiary. 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 us.





At
      the end of 2005,
      we h ad
      the capability to issue $111 million of additional FMB on the basis of
      property additions and retired bonds under the terms of our mortgage indenture
      following the recently completed intra-system transfer of generating assets
      (see
      Note 14). Our issuance of FMB is subject to a provision of our senior note
      indenture generally limiting the incurrence of additional secured debt, subject
      to certain exceptions that would permit, among other things, the issuance of
      secured debt (including FMB) (i) supporting pollution control notes or similar
      obligations, or (ii) as an extension, renewal or replacement of previously
      outstanding secured debt. In addition, this provision would permit us to incur
      additional secured debt not otherwise permitted by a specified exception of
      up
      to $582 million as of December 31, 2005. We have no restrictions on
      the issuance of preferred stock.





On
      June 14,
      2005, we, FirstEnergy, OE, Penn, TE, JCP&L, Met-Ed, Penelec, FES and ATSI,
      as Borrowers, entered into a syndicated $2 billion five-year revolving
      credit facility. Borrowings under the facility are available to each Borrower
      separately and mature on the earlier of 364 days from the date of borrowing
      and the commitment expiration date, as the same may be extended. Our borrowing
      limit under the facility is $250 million subject to applicable regulatory
      approvals.





Under
      the revolving
      credit facility, borrowers may request the issuance of letters of credit
      expiring up to one year from the date of issuance. The stated amount of
      outstanding LOC will count against total commitments available under the
      facility and against the applicable borrower’s borrowing sub-limit. Total unused
      borrowing capability under existing credit facilities and accounts receivable
      financing facilities totaled $310 million as of December 31,
      2005.





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
      December 31, 2005, our debt to total capitalization as defined under the
      revolving credit facility, was 53%.





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




8


We
      have the
      ability to borrow from our regulated affiliates and FirstEnergy to meet our
      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 2005 was 3.24%.





On
      July 18, 2005, Moody’s revised its rating outlook on FirstEnergy and its
      subsidiaries to positive from stable. Moody’s stated that the revision to
      FirstEnergy’s outlook resulted from steady financial improvement and steps taken
      by management to improve operations, including the stabilization of its nuclear
      operations. On October 3, 2005, S&P raised its corporate credit rating
      on FirstEnergy and the EUOC to 'BBB' from 'BBB-'. At the same time, S&P
      raised the senior unsecured ratings at the holding company to 'BBB-' from 'BB+'
      and each of the EUOC by one notch above the previous rating. S&P noted that
      the upgrade followed the continuation of a good operating track record,
      specifically for the nuclear fleet through the third quarter of 2005. On
      December 23, 2005, Fitch revised its rating outlook on FirstEnergy and its
      subsidiaries to positive from stable. Fitch stated that the revision to
      FirstEnergy's outlook resulted from improved performance of the Company's
      generating fleet and ongoing debt reduction.





Our
      access to
      capital markets and costs of financing are dependent on the ratings of our
      securities and the securities of FirstEnergy. The following table shows
      securities ratings as of December 31, 2005. The ratings outlook from
      S&P on all such securities is stable. The ratings outlook from Moody's &
Fitch on all securities is positive.





**Ratings
                of Securities**
            
            **Securities**
            
            **S&P**
            
            **Moody’s**
            
            **Fitch****FirstEnergy**
            
            
            Senior
                unsecured
            
            
            BBB-
            
            
            Baa3
            
            
            BBB-**CEI**
            
            
            Senior
                secured
            
            
            BBB
            
            
            Baa2
            
            
            BBB-Senior
                unsecured
            
            
            BBB-
            
            
            Baa3
            
            
            BB+





*Cash
      Flows from
      Investing Activities*





Net
      cash used for
      investing activities decreased $72 million in 2005 compared to 2004. This
      decrease was primarily due to increased loan activity with associated companies.
      The $466 million increase in collection of principal amounts on long-term notes
      receivable in 2005 included a $375 million repayment from NGC and $91 million
      from ATSI. The $375 million received from NGC related to the nuclear generation
      asset transfer that occurred on December 16, 2005. This increase in collection
      from associated companies was partially offset by $388 million in loan payments
      to the money pool in 2005, compared to $10 million in loan repayments from
      associated companies in 2004. Higher expenditures for property additions were
      substantially offset by increased investments in lessor notes.





Net
      cash used for
      investing activities increased $30 million in 2004 compared to 2003 and
      primarily reflected increased investments in lessor notes, partially offset
      by
      increased loan payments received from associated companies and lower
      expenditures for property additions.





Our
      capital spending
      for the period 2006-2010 is expected to be about $600 million of which
      approximately $107 million applies to 2006. The capital spending is
      primarily for property additions supporting the distribution of electricity.
      In
      addition, there is capital spending for the leasehold interests in certain
      generating plants retained after the generation assets transfers.





**Contractual
      Obligations**





As
      of
      December 31, 2005, our estimated cash payments under existing contractual
      obligations that we consider firm obligations are as follows:





**2007-**
            
            **2009-****Contractual
                Obligations**
            
            **Total**
            
            **2006**
            
            **2008**
            
            **2010**
            
            **Thereafter*****(In
                millions)***Long-term
                debt(1)
            
            $
            2,004
            
            $
            -
            
            $
            269
            
            $
            180
            
            $
            1,555Short-term
                borrowings
            
            
            352
            
            
            352
            
            
            -
            
            
            -
            
            
            -Capital
                leases
            
            
            7
            
            
            1
            
            
            2
            
            
            2
            
            
            2Operating
                leases(2)
            
            
            194
            
            
            19
            
            
            28
            
            
            24
            
            
            123Purchases(3)
            
            
            343
            
            
            47
            
            
            100
            
            
            96
            
            
            100Total
            
            $
            2,900
            
            $
            419
            
            $
            399
            
            $
            302
            
            $
            1,780





(1)  Amounts
      reflected do
      not include interest on long-term debt.


(2)  Operating
      lease
      payments are net of capital trust receipts of $497.6 million (see
      Note 5).


(3)  Fuel
      and power
      purchases under contracts with fixed or minimum quantities and approximate
      timing.




9


**Off-Balance
      Sheet Arrangements**





We
      have obligations
      not included on our Consolidated Balance Sheets related to sale and leaseback
      arrangements involving the Bruce Mansfield Plant, which is reflected in the
      operating lease payments above (see Note 5 - Leases). As of
      December 31, 2005, the present value of these operating lease commitments,
      net of trust investments, total $105 million.





In
      June 2005, the
      CFC receivables financing structure was renewed and restructured from an
      off-balance-sheet transaction to an on-balance-sheet transaction. Under the
      new
      structure, any borrowings under the facility appear on our Consolidated Balance
      Sheets as short-term debt.





**Interest
      Rate Risk**





Our
      exposure to
      fluctuations in market interest rates is reduced since a significant portion
      of
      our debt has fixed interest rates. The table below presents principal amounts
      and related weighted average interest rates by year of maturity for our
      investment portfolio, debt obligations and preferred stock with mandatory
      redemption provisions.





**Comparison
                of Carrying Value to Fair Value****There-**
            
            
            
            **Fair****Year
                of Maturity**
            
            **2006**
            
            **2007**
            
            **2008**
            
            **2009**
            
            **2010**
            
            **after**
            
            **Total**
            
            **Value*****(Dollars
                in millions)***AssetsInvestments
                Other Than Cashand
                Cash
                Equivalents-Fixed
                Income
            
            $
            44
            
            $
            36
            
            $
            38
            
            $
            40
            
            $
            52
            
            $
            1,415
            
            **$**
            1,625
            
            **$**
            1,678Average
                interest rate
            
            
            7.8
            %
            
            7.7
            %
            
            7.7
            %
            
            7.7
            %
            
            7.7
            %
            
            6.4
            %
            
            6.6%LiabilitiesLong-term
                Debt
                and OtherLong-Term
                Obligations:Fixed
                rate
            
            
            
            
            $
            129
            
            $
            140
            
            $
            162
            
            $
            18
            
            $
            1,044
            
            **$**
            1,493
            
            **$**
            1,645Average
                interest rate
            
            
            
            
            
            7.2
            %
            
            7.0
            %
            
            7.5
            %
            
            7.7
            %
            
            6.9
            %
            
            7.0
            %Variable
                rate
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            $
            511
            
            **$**
            511
            
            **$**
            511Average
                interest rate
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            3.4
            %
            
            3.4
            %Short-term
                Borrowings
            
            $
            352
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            **$**
            352
            
            **$**
            352Average
                interest rate
            
            
            4.2
            %
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            4.2
            %





**Outlook**





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





*Regulatory
      Matters*





Regulatory
      assets
      are costs which have been authorized by the PUCO 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 our transition plan and rate
      restructuring plan.





On
      May 27,
      2005, we filed an application with the PUCO to establish a GCAF rider under
      the
      RSP which had been approved by the PUCO in August 2004. The GCAF application
      sought recovery of increased fuel costs from 2006 through 2008 applicable to
      our
      retail customers through a tariff rider to be implemented January 1, 2006.
      The application reflected projected increases in fuel costs in 2006 compared
      to
      2002 baseline costs. The new rider, after adjustments made in testimony, sought
      to recover all costs above the baseline (approximately $88 million in 2006
      for all the Ohio Companies). Various parties including the OCC intervened in
      this case and the case was consolidated with the RCP application discussed
      below. On November 1, 2005, we filed tariffs in compliance with the RSP,
      which were approved by the PUCO on December 7, 2005.





On
      September 9,
      2005, we filed an application with the PUCO that supplemented our existing
      RSP
      with an RCP which was designed to provide customers with more certain rate
      levels than otherwise available under the RSP during the plan period. Major
      provisions of the RCP include:




10





•
              Maintain
                  our
                  existing level of base distribution rates through April 30,
                  2009,•
              Defer
                  and
                  capitalize for future recovery 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;•
              Adjust
                  the RTC
                  and Extended RTC recovery periods and rate levels so that full
                  recovery of
                  our authorized costs will occur as of December 31,
                  2010,•
              Reduce
                  our
                  deferred shopping incentive balances as of January 1, 2006 by up
                  to $85
                  million by accelerating the application of our accumulated cost
                  of removal
                  regulatory liability; and•
              Defer
                  and
                  capitalize all of our allowable fuel cost increases until January
                  1,
                  2009.







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****Period**
            
            **Amortization*****(In
                millions)***2006
            
            $
            1002007
            
            
            1112008
            
            
            1292009
            
            
            2162010
            
            
            268**Total
                Amortization**
            
            **$**
            **824**





On
      November 4,
      2005, a supplemental stipulation was filed with the PUCO which was in addition
      to a stipulation filed with the September 9, 2005 application. On
      January 4, 2006, the PUCO approved the RCP filing with modifications. On
      January 10, 2006, we filed a Motion for Clarification of the PUCO order
      approving the RCP. We 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. We
      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, our previous
      requests and clarifying issues referred to above. The PUCO granted our requests
      to: 1) recognize fuel and distribution deferrals commencing January 1,
      2006; 2) recognize distribution deferrals on a monthly basis prior to review
      by
      the PUCO Staff; 3) clarify that the types of distribution expenditures included
      in the Supplemental Stipulation may be deferred; and 4) clarify that
      distribution expenditures do not have to be “accelerated” in order to be
      deferred. The PUCO granted our 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 our Motion. On February 3, 2006, several
      other parties filed applications for rehearing on the PUCO's January 4,
      2006 Order. We responded to the application for rehearing on February 13,
      2006.





Under
      provisions of
      the RSP, the PUCO may require us to undertake, no more often than annually,
      a
      competitive bid process to secure generation for the years 2007 and 2008. On
      July 22, 2005, we filed a competitive bid process for the period beginning
      in 2007 that is similar to the competitive bid process approved by the PUCO
      for
      us in 2004 which resulted in the PUCO accepting no bids. Any acceptance of
      future competitive bid results would terminate the RSP pricing, with no
      accounting impacts to the RSP, and not until twelve months after the PUCO
      authorizes such termination. On September 28, 2005, the PUCO issued an
      Entry that essentially approved our filing but delayed the proposed timing
      of
      the competitive bid process by four months, calling for the auction to be held
      on March 21, 2006. OCC filed an application for rehearing of the
      September 28, 2005 Entry, which the PUCO denied on November 22, 2005.
      On February 23, 2006, the auction manager notified the PUCO that there was
      insufficient interest in the auction process to allow it to proceed in
      2006.





On
      August 31,
      2005, the PUCO approved our settlement stipulation for a rider to recover
      transmission and ancillary service-related costs beginning January 1, 2006,
      to be adjusted each July 1 thereafter. The incremental transmission and
      ancillary service revenues expected to be recovered from January through June
      2006 are approximately $24 million, including recovery of the 2005 deferred
      MISO expenses as described below. In May 2006, we will file a modification
      to
      the rider to determine revenues from July 2006 through June 2007. On
      January 20,
      2006, the OCC sought rehearing of the PUCO approval of the rider recovery during
      the period January 1, 2006 through June 30, 2006, as that amount
      pertains to recovery of the deferred costs. The PUCO denied the OCC's
      application on February 6, 2006. The OCC has sixty days from that date to
      appeal the PUCO's approval of the rider.




11


In
      response to our
      December 2004 application for authority to defer costs associated with
      transmission and ancillary service-related costs incurred during the period
      October 1, 2003 through December 31, 2005, the PUCO granted the
      accounting authority in May 2005 for us 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 us to accrue
      carrying charges on the deferred balances. On August 31, 2005, the OCC
      appealed the PUCO's decision. All briefs have been filed. A motion to dismiss
      filed on behalf of the PUCO is currently pending. Unless the court grants the
      motion, the appeal will be set for oral argument, which should be heard in
      the
      second half of 2006.





We
      are 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. We will continue to periodically assess the
      FERC-ordered Reliability Study recommendations for forecasted 2009 system
      conditions, recognizing revised load forecasts and other changing system
      conditions which may impact the recommendations. Thus far, implementation of
      the
      recommendations has not required, nor is expected to require, substantial
      investment in new, or material upgrades to existing, equipment. The FERC or
      other applicable government agencies and reliability coordinators, however,
      may
      take a different view as to recommended enhancements or may recommend additional
      enhancements in the future as the result of adoption of mandatory reliability
      standards pursuant to EPACT that could require additional, material
      expenditures. Finally, the PUCO is continuing to review our filing that
      addressed upgrades to control room computer hardware and software and
      enhancements to the training of control room operators before determining the
      next steps, if any, in the proceeding.





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
      NERC has been
      preparing the implementation aspects of reorganizing its structure to meet
      the
      FERC’s certification requirements for the ERO. The NERC will make a filing with
      the FERC to obtain certification as the ERO and to obtain FERC approval of
      delegation agreements with regional entities. The new FERC rule referred to
      above, further provides for reorganizing regional reliability organizations
      (regional entities) that would replace the current regional councils and for
      rearranging the relationship with the ERO. The “regional entity” may be
      delegated authority by the ERO, subject to FERC approval, for enforcing
      reliability standards adopted by the ERO and approved by the FERC. NERC also
      intends to make a parallel filing with the FERC seeking approval of mandatory
      reliability standards. These
      reliability
      standards are expected to be based on the current NERC Version 0 reliability
      standards with some additional standards. The
      two filings are
      expected to be made in the second quarter of 2006.





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
      a parallel path,
      the NERC is establishing working groups to develop reliability standards to
      be
      filed for approval with the FERC following the NERC’s certification as an ERO.
      These reliability standards are expected to build on the current NERC Version
      0
      reliability standards. It is expected that the proposed reliability standards
      will be filed with the FERC in early 2006.





We
      believe that we
      are in compliance with all current NERC reliability standards. However, it
      is
      expected that the FERC will adopt stricter reliability standards than those
      contained in the current NERC Version 0 standards. The financial impact of
      complying with the new standards cannot be determined at this time. However,
      EPACT requires that all prudent costs incurred to comply with the new
      reliability standards be recovered in rates. If we are unable to meet the
      reliability standards for the bulk power system in the future, it could have
      a
      material adverse effect on our financial condition, results of operations and
      cash flows.





On
      November 1, 2005,
      FES filed two power sales agreements for approval with the FERC. One power
      sales
      agreement provided for FES to provide the PLR requirements of the Ohio
      Companies at a price equal to the retail generation rates approved by the PUCO
      for a period of three years beginning January 1, 2006. The Ohio Companies will
      be relieved of their obligation to obtain PLR power requirements from FES if
      the
      Ohio competitive bid process, mandated by the PUCO, 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. Penn has filed a plan with the PPUC to
      use
      an RFP process to obtain its power supply requirements after 2006.




12


On
      December 29,
      2005, the FERC issued an order setting the two power sales agreements for
      hearing. The order criticizes the Ohio competitive bid process, and requires
      FES
      to submit additional evidence in support of the reasonableness of the prices
      charged in the two power sales agreements. A pre-hearing conference was held
      on
      January 18, 2006 to determine the hearing schedule in this case. FES
      expects an initial decision to be issued in this case in the fall of 2006.
      The
      outcome of this proceeding cannot be predicted. FES has sought rehearing of
      the
      December 29, 2005 order.





See
      Note 9 to
      the consolidated financial statements for further details and a complete
      discussion of regulatory matters in Ohio.





*Environmental
      Matters*





We
      accrue
      environmental liabilities only when we conclude that it is probable that we
      have an obligation for such costs and can reasonably estimate the amount of
      such
      costs. Unasserted claims are reflected in our 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 our future risks and mitigation
      efforts. The report is available on its website at www.firstenergycorp.com/environmental .





*Regulation
      of
      Hazardous Waste*





We
      have 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 December 31, 2005, based
      on estimates of the total costs of cleanup, our proportionate responsibility
      for
      such costs and the financial ability of other unaffiliated entities to pay.
      Included in Other Noncurrent Liabilities are accrued liabilities aggregating
      approximately $1.7 million as of December 31, 2005.





See
      Note 13(B)
      to the consolidated financial statements for further details and a complete
      discussion of environmental matters.





*Other
      Legal
      Proceedings*





*Power
      Outage and
      Related Litigation-*





On
      August 14,
      2003, various states and parts of southern Canada experienced widespread power
      outages. The outages affected approximately 1.4 million customers in
      FirstEnergy’s service area. The U.S. - Canada Power System Outage Task Force’s
      final report in April 2004 on the outages concludes, among other things, that
      the problems leading to the outages began in our 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
      our
      system; inadequate situational awareness of the developing conditions; and
      a
      perceived failure to adequately manage tree growth in certain transmission
      rights of way. The Task Force also concluded that there was a failure of the
      interconnected grid's reliability organizations (MISO and PJM) to provide
      effective real-time diagnostic support. The final report is publicly available
      through the Department of Energy’s website (www.doe.gov). We believe 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. We remain
      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. We 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 our electric system. Our implementation
      of these recommendations in 2004 included completion of the Task Force
      recommendations that were directed toward FirstEnergy. We also are proceeding
      with the implementation of the
      recommendations regarding enhancements to regional reliability that were to
      be
      completed subsequent to 2004 and will continue to periodically assess the
      FERC-ordered Reliability Study recommendations for forecasted 2009 system
      conditions, recognizing revised load forecasts and other changing system
      conditions which may impact the recommendations. Thus far implementation of
      the
      recommendations has not required, nor is expected to require, substantial
      investment in new or material upgrades, to existing equipment, and therefore
      we
      have not accrued a liability as of December 31, 2005 for any expenditures
      in excess of those actually incurred through that date. We note, however, that
      the FERC or other applicable government agencies and reliability coordinators
      may take a different view as to recommended enhancements or may recommend
      additional enhancements in the future that could require additional, material
      expenditures. Finally, the PUCO is continuing to review our filing that
      addressed upgrades to control room computer hardware and software and
      enhancements to the training of control room operators before determining the
      next steps, if any, in the proceeding.




13


FirstEnergy
      companies are also defending six separate complaint cases before the PUCO
      relating to the August 14, 2003 power outage. Two cases were originally
      filed in Ohio State courts but were subsequently dismissed for lack of subject
      matter jurisdiction and further appeals were unsuccessful. In these cases the
      individual complainants—three in one case and four in the other—sought to
      represent others as part of a class action. The PUCO dismissed the class
      allegations, stating that its rules of practice do not provide for class action
      complaints. Of the four other pending PUCO complaint cases, three were filed
      by
      various insurance carriers either in their own name as subrogees or in the
      name
      of their insured. In each of the four cases, the carriers seek reimbursement
      against various FirstEnergy companies (and, in one case, from PJM, MISO and
      American Electric Power Company as well) for claims paid to insureds for claims
      allegedly arising as a result of the loss of power on August 14, 2003. The
      listed insureds in these cases, in many instances, are not customers of any
      FirstEnergy company. The fourth case involves the claim of a non-customer
      seeking reimbursement for losses incurred when its store was burglarized on
      August 14, 2003. In addition to these six cases, the Ohio Companies were
      named as respondents in a regulatory proceeding that was initiated at the PUCO
      in response to complaints alleging failure to provide reasonable and adequate
      service stemming primarily from the August 14, 2003 power outages. No
      estimate of potential liability has been undertaken for any of these cases.





We
      are 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 our 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 CEI, OE, 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. The transfer consisted of our prior
      interests in Beaver Valley Unit 2 (24.47%), Davis-Besse (51.38%) and Perry
      (44.85%).





On
      January 20,
      2006, FENOC announced that it has entered into a deferred prosecution agreement
      with the U.S. Attorney’s Office for the Northern District of Ohio and the
      Environmental Crimes Section of the Environment and Natural Resources Division
      of the DOJ related to FENOC’s communications with the NRC during the fall of
      2001 in connection with the reactor head issue at the Davis-Besse Nuclear Power
      Station. Under the agreement, which expires on December 31, 2006, the United
      States acknowledged FENOC’s extensive corrective actions at Davis-Besse, FENOC’s
      cooperation during investigations by the DOJ and the NRC, FENOC’s pledge of
      continued cooperation in any related criminal and administrative investigations
      and proceedings, FENOC’s acknowledgement of responsibility for the behavior of
      its employees, and its agreement to pay a monetary penalty. The DOJ will refrain
      from seeking an indictment or otherwise initiating criminal prosecution of
      FENOC
      for all conduct related to the statement of facts attached to the deferred
      prosecution agreement, as long as FENOC remains in compliance with the
      agreement, which FENOC fully intends to do. FENOC has agreed to pay a penalty
      of
      $28 million (which is not deductible for income tax purposes) which reduced
      FirstEnergy's earnings by $0.09 per common share in the fourth quarter of 2005.
      As part of the deferred prosecution agreement entered into with the DOJ,
      $4.35 million of that amount will be directed to community service
      projects.





On
      April 21,
      2005, the NRC issued a NOV and proposed a $5 million civil penalty related
      to the degradation of the Davis-Besse reactor vessel head issue described above.
      We accrued $1.0 million for a potential fine prior to 2005 and accrued the
      remaining liability for our share of the proposed fine of $1.8 million
      during the first quarter of 2005. On September 14, 2005, FENOC filed its
      response to the NOV with the NRC. FENOC accepted full responsibility for the
      past failure to properly implement its boric acid corrosion control and
      corrective action programs. The NRC NOV indicated that the violations do not
      represent current licensee performance. We 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.





Effective
      July 1, 2005 the NRC oversight panel for Davis-Besse was terminated and
      Davis-Besse returned to the standard NRC reactor oversight process. At that
      time, NRC inspections were augmented to include inspections to support the
      NRC's
      Confirmatory Order dated March 8, 2004 that was issued at the time of
      startup and to address an NRC White Finding related to the performance of the
      emergency sirens. By letter dated December 8, 2005, the NRC advised FENOC
      that the White Finding had been closed.





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.




14


On
      April 4,
      2005, the NRC held a public meeting to discuss FENOC’s performance at the Perry
      Nuclear Power Plant as identified in the NRC's annual assessment letter to
      FENOC. Similar public meetings are held with all nuclear power plant licensees
      following issuance by the NRC of their annual assessments. According to the
      NRC,
      overall the Perry Plant operated "in a manner that preserved public health
      and
      safety" even though it remained under heightened NRC oversight. During the
      public meeting and in the annual assessment, the NRC indicated that additional
      inspections will continue and that the plant must improve performance to be
      removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action
      Matrix. By an inspection report dated January 18, 2006, the NRC closed one
      of the White Findings (related to emergency preparedness) which led to the
      multiple degraded cornerstones.





On
      May 26,
      2005, the NRC held a public meeting to discuss its oversight of the Perry Plant.
      While the NRC stated that the plant continued to operate safely, the NRC also
      stated that the overall performance had not substantially improved since the
      heightened inspection was initiated. The NRC reiterated this conclusion in
      its
      mid-year assessment letter dated August 30, 2005. On September 28,
      2005, the NRC sent a CAL to FENOC describing commitments that FENOC had made
      to
      improve the performance of Perry and stated that the CAL would remain open
      until
      substantial improvement was demonstrated. The CAL was anticipated as part of
      the
      NRC's Reactor Oversight Process. If performance does not improve, the NRC has
      a
      range of options under the Reactor Oversight Process, from increased oversight
      to possible impact to the plant’s operating authority. Although unable to
      predict a potential impact, its ultimate disposition 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 our normal business operations pending against us. The other
      potentially material items not otherwise discussed above are described
      below.





On
      October 20,
      2004, FirstEnergy was notified by the SEC that the previously disclosed informal
      inquiry initiated by the SEC's Division of Enforcement in September 2003
      relating to the restatements in August 2003 of previously reported results
      by
      FirstEnergy and the Ohio Companies, and the Davis-Besse extended outage, have
      become the subject of a formal order of investigation. The SEC's formal order
      of
      investigation also encompasses issues raised during the SEC's examination of
      FirstEnergy and the Companies under the PUHCA. Concurrent with this
      notification, FirstEnergy received a subpoena asking for background documents
      and documents related to the restatements and Davis-Besse issues. On
      December 30, 2004, FirstEnergy received a subpoena asking for documents
      relating to issues raised during the SEC's PUHCA examination. On August 24,
      2005 additional information was requested regarding Davis-Besse. FirstEnergy
      has
      cooperated fully with the informal inquiry and 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 a tariff that would specifically
      allow the collection of transition charges from customers of municipal electric
      utilities formed after 1998.
      An adverse ruling could negatively affect full recovery of transition charges
      by
      the utility. Hearings on the matter were held in August 2005. Initial briefs
      from all parties were filed on September 22, 2005 and reply briefs were
      filed on October 14, 2005. It is unknown when the PUCO will decide this
      case.





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





See
      Note 13(C)
      to the consolidated financial statements for further details and a complete
      discussion of other legal proceedings.





**Critical
      Accounting Policies**





We
      prepare our
      consolidated financial statements in accordance with GAAP. Application of these
      principles often requires a high degree of judgment, estimates and assumptions
      that affect financial results. All of our assets are subject to their own
      specific risks and uncertainties and are regularly reviewed for impairment.
      Our
      more significant accounting policies are described below.





*Regulatory
      Accounting*





We
      are subject to
      regulation that sets the prices (rates) we are permitted to charge our customers
      based on the costs that the regulatory agencies determine we are permitted
      to
      recover. At times, regulators permit the future recovery through rates of costs
      that would be currently charged to expense by an unregulated company. This
      rate-making process results in the recording of regulatory assets based on
      anticipated future cash inflows. We regularly review these assets to assess
      their ultimate recoverability within the approved regulatory guidelines.
      Impairment risk associated with these assets relates to potentially adverse
      legislative, judicial or regulatory actions in the future.




15


*Revenue
      Recognition*





We
      follow the
      accrual method of accounting for revenues, recognizing revenue for electricity
      that has been delivered to customers but not yet billed through the end of
      the
      accounting period. The determination of electricity sales to individual
      customers is based on meter readings, which occur on a systematic basis
      throughout the month. At the end of each month, electricity delivered to
      customers since the last meter reading is estimated and a corresponding accrual
      for unbilled sales is recognized. The determination of unbilled sales requires
      management to make estimates regarding electricity available for retail load,
      transmission and distribution line losses, demand by customer class,
      weather-related impacts, prices in effect for each customer class and
      electricity provided by alternative suppliers.





*Pension
      and
      Other Postretirement Benefits Accounting*





Our
      reported costs
      of providing non-contributory defined pension benefits and postemployment
      benefits other than pensions are dependent upon numerous factors resulting
      from
      actual plan experience and certain assumptions.





Pension
      and OPEB
      costs are affected by employee demographics (including age, compensation levels,
      and employment periods), the level of contributions we make to the plans, and
      earnings on plan assets. Such factors may be further affected by business
      combinations, which impact employee demographics, plan experience and other
      factors. Pension and OPEB costs are also affected by changes to key assumptions,
      including anticipated rates of return on plan assets, the discount rates and
      health care trend rates used in determining the projected benefit obligations
      for pension and OPEB costs.





In
      accordance with
      SFAS 87, changes in pension and OPEB obligations associated with these
      factors may not be immediately recognized as costs on the income statement,
      but
      generally are recognized in future years over the remaining average service
      period of plan participants. SFAS 87 and SFAS 106 delay recognition of
      changes due to the long-term nature of pension and OPEB obligations and the
      varying market conditions likely to occur over long periods of time. As such,
      significant portions of pension and OPEB costs recorded in any period may not
      reflect the actual level of cash benefits provided to plan participants and
      are
      significantly influenced by assumptions about future market conditions and
      plan
      participants' experience.





In
      selecting an
      assumed discount rate, we consider currently available rates of return on
      high-quality fixed income investments expected to be available during the period
      to maturity of the pension and other postretirement benefit obligations. Due
      to
      recent declines in corporate bond yields and interest rates in general, we
      reduced the assumed discount rate as of December 31, 2005 to 5.75% from
      6.00% and 6.25% used as of December 31, 2004 and 2003, respectively.





Our
      assumed rate of
      return on pension plan assets considers historical market returns and economic
      forecasts for the types of investments held by our pension trusts. In 2005,
      2004
      and 2003, plan assets actually earned $325 million or 8.2%,
      $415 million or 11.1% and
      $671 million or 24.2%, respectively. Our pension costs in 2005, 2004 and
      2003 were computed using an assumed 9.0% rate of return on plan assets which
      generated $345 million, $286 million and $248 million expected
      returns on plan assets, respectively. The 2005 expected return was based upon
      projections of future returns and our pension trust investment allocation of
      approximately 63% equities, 33% bonds, 2% real estate and 2% cash. The gains
      or
      losses generated as a result of the difference between expected and actual
      return on plan assets are deferred and amortized and will increase or decrease
      future net periodic pension expense, respectively.





In
      the fourth
      quarter of 2005, FirstEnergy made a $500 million voluntary contribution to
      its pension plan (our share was $93 million). As a result of our voluntary
      contribution and the increased market value of pension plan assets, we
      recognized a prepaid benefit cost of $139 million as of December 31,
      2005. As prescribed by SFAS 87, we eliminated our additional minimum
      liability of $51 million and its intangible asset of $14 million. In
      addition, the entire AOCL balance was credited by $22 million (net of
      $15 million in deferred taxes) as the fair value of trust assets exceeded
      the accumulated benefit obligation as of December 31, 2005.





Health
      care cost
      trends continue to increase and will affect future OPEB costs. The 2005 and
      2004
      composite health care trend rate assumptions are approximately 9-11%, gradually
      decreasing to 5% in later years. In determining our trend rate assumptions,
      we
      included the specific provisions of our health care plans, the demographics
      and
      utilization rates of plan participants, actual cost increases experienced in
      our
      health care plans, and projections of future medical trend rates. The effect
      on
      CEI's portion of pension and OPEB costs from changes in key assumptions are
      as
      follows:




**Increase
                  in Costs from Adverse Changes in Key Assumptions****Assumption**
              
              **Adverse
                  Change**
              
              **Pension**
              
              **OPEB**
              
              **Total*****(In
                  millions)***Discount
                  rate
              
              
              Decrease
                  by 0.25%
              
              $
              0.7
              
              $
              0.3
              
              $
              1.0Long-term
                  return on assets
              
              
              Decrease
                  by 0.25%
              
              $
              0.7
              
              $
              -
              
              $
              0.7Health
                  care
                  trend rate
              
              
              Increase
                  by 1%
              
              
              na
              
              $
              2.3
              
              $
              2.3


16


*Ohio
      Transition
      Cost Amortization*





In
      connection with
      our Ohio transition plan, the PUCO determined allowable transition costs based
      on amounts recorded on our regulatory books. These costs exceeded those deferred
      or capitalized on our balance sheet prepared under GAAP since they included
      certain costs which have not yet been incurred or that were recognized on the
      regulatory financial statements (fair value purchase accounting adjustments).
      We
      use an effective interest method for amortizing transition costs, often referred
      to as a "mortgage-style" amortization. The interest rate under this method
      is
      equal to the rate of return authorized by the PUCO in our RSP. In computing
      the
      transition cost amortization, we include only the portion of the transition
      revenues associated with transition costs included on the balance sheet prepared
      under GAAP. Revenues collected for the off balance sheet costs and the return
      associated with these costs are recognized as income when received. Amortization
      of deferred customer shopping incentives and interest costs will be equal to
      the
      related revenue recovery that is recognized under the RCP (see Note
      2(A)).





*Long-Lived
      Assets*





In
      accordance with
      SFAS 144, we periodically evaluate our long-lived assets to determine
      whether conditions exist that would indicate that the carrying value of an
      asset
      might not be fully recoverable. The accounting standard requires that if the
      sum
      of future cash flows (undiscounted) expected to result from an asset is less
      than the carrying value of the asset, an asset impairment must be recognized
      in
      the financial statements. If impairment has occurred, we recognize a loss -
      calculated as the difference between the carrying value and the estimated fair
      value of the asset (discounted future net cash flows).





The
      calculation of
      future cash flows is based on assumptions, estimates and judgment about future
      events. The aggregate amount of cash flows determines whether an impairment
      is
      indicated. The timing of the cash flows is critical in determining the amount
      of
      the impairment.





*Goodwill*





In
      a business
      combination, the excess of the purchase price over the estimated fair values
      of
      the assets acquired and liabilities assumed is recognized as goodwill. Based
      on
      the guidance provided by SFAS 142, we evaluate our goodwill for impairment
      at least annually and would make such an evaluation more frequently if
      indicators of impairment should arise. In accordance with the accounting
      standard, if the fair value of a reporting unit is less than its carrying value
      (including goodwill), the goodwill is tested for impairment. If an impairment
      were indicated, we recognize a loss - calculated as the difference between
      the
      implied fair value of our goodwill and the carrying value of the goodwill.
      Our
      annual review was completed in the third quarter of 2005, with no impairment
      of
      goodwill indicated. The forecasts used in our evaluation of goodwill reflect
      operations consistent with our general business assumptions. Unanticipated
      changes in those assumptions could have a significant effect on our future
      evaluations of goodwill. In the year ended December 31, 2005, we adjusted
      goodwill to reverse pre-merger tax accruals due to the final resolution of
      tax
      contingencies related to the Centerior acquisition. As of December 31,
      2005, we had approximately $1.7 billion of goodwill.





*Asset
      Retirement
      Obligations*





In
      accordance with
      SFAS 143 and FIN 47, we recognize an ARO for the future
      decommissioning of our nuclear power plants and future remediation of other
      environmental liabilities associated with all of our long-lived assets. The
      ARO
      liability represents an estimate of the fair value of our current obligation
      related to nuclear decommissioning and the retirement or remediation of
      environmental liabilities of other assets. A fair value measurement inherently
      involves uncertainty in the amount and timing of settlement of the liability.
      We
      use an expected cash flow approach to measure the fair value of the nuclear
      decommissioning and environmental remediation ARO. This approach applies
      probability weighting to discounted future cash flow scenarios that reflect
      a
      range of possible outcomes. The scenarios consider settlement of the ARO at
      the
      expiration of the nuclear power plants' current license, settlement based on
      an
      extended license term and expected remediation dates.





**NEW
      ACCOUNTING STANDARDS AND INTERPRETATIONS**





*FSP
      FAS 115-1
      and FAS 124-1, "The Meaning of Other-Than-Temporary Impairment and its
      Application to Certain Investments"*





Issued
      in November
      2005, FSP 115-1 and FAS 124-1 addresses the determination as to when an
      investment is considered impaired, whether that impairment is other than
      temporary, and the measurement of an impairment loss. The FSP finalized and
      renamed EITF 03-1 and 03-1-a to FSP FAS 115-1. This FSP will (1) nullify certain
      requirements of Issue 03-1 and supersedes EITF topic No. D-44, "Recognition
      of
      Other Than Temporary Impairment upon the Planned Sale of a Security Whose Cost
      Exceeds Fair Value," (2) clarify that an investor should recognize an impairment
      loss no later than when the impairment is deemed other than temporary, even
      if a
      decision to sell has not been made, and (3) be effective for
      other-than-temporary impairment and analyses conducted in periods beginning
      after September 15, 2005. The FSP requires prospective application with an
      effective date for reporting periods beginning after December 15, 2005. We
      are currently evaluating this FSP and any impact on our
      investments.




17


*EITF
      Issue
      04-13, "Accounting for Purchases and Sales of Inventory with the Same
      Counterparty"*





In
      September 2005,
      the EITF reached a final consensus on Issue 04-13 concluding that two or more
      legally separate exchange transactions with the same counterparty should be
      combined and considered as a single arrangement for purposes of applying
      APB 29, when the transactions were entered into "in contemplation" of one
      another. If two transactions are combined and considered a single arrangement,
      the EITF reached a consensus that an exchange of inventory should be accounted
      for at fair value. Although electric power is not capable of being held in
      inventory, there is no substantive conceptual distinction between exchanges
      involving power and other storable inventory. Therefore, we will adopt this
      EITF
      effective for new arrangements entered into, or modifications or renewals of
      existing arrangements, in interim or annual periods beginning after
      March 15, 2006.





*SFAS
                154 -
                “Accounting Changes and Error Corrections - a replacement of APB Opinion
                No. 20 and FASB Statement No.
                3”*





In
      May 2005, the
      FASB issued SFAS 154 to change the requirements for accounting and
      reporting a change in accounting principle. It applies to all voluntary changes
      in accounting principle and to changes required by an accounting pronouncement
      when that pronouncement does not include specific transition provisions. This
      Statement requires retrospective application to prior periods’ financial
      statements of changes in accounting principle, unless it is impracticable to
      determine either the period-specific effects or the cumulative effect of the
      change. In those instances, this Statement requires that the new accounting
      principle be applied to the balances of assets and liabilities as of the
      beginning of the earliest period for which retrospective application is
      practicable and that a corresponding adjustment be made to the opening balance
      of retained earnings (or other appropriate components of equity or net assets
      in
      the statement of financial position) for that period rather than being reported
      in the Consolidated Statements of Income. This Statement also requires that
      a
      change in depreciation, amortization, or depletion method for long-lived,
      nonfinancial assets be accounted for as a change in accounting estimate affected
      by a change in accounting principle. The provisions of this Statement are
      effective for accounting changes and corrections of errors made in fiscal years
      beginning after December 15, 2005. We adopted this Statement effective
      January 1, 2006.





*SFAS
                153,
                “Exchanges of Nonmonetary Assets - an amendment of APB Opinion No.
                29”*





In
      December 2004,
      the FASB issued SFAS 153 amending APB 29, which was based on the
      principle that nonmonetary assets should be measured based on the fair value
      of
      the assets exchanged. The guidance in APB 29 included certain exceptions to
      that principle. SFAS 153 eliminates the exception from fair value
      measurement for nonmonetary exchanges of similar productive assets and replaces
      it with an exception for exchanges that do not have commercial substance. This
      Statement specifies that a nonmonetary exchange has commercial substance if
      the
      future cash flows of the entity are expected to change significantly as a result
      of the exchange. The provisions of this Statement are effective January 1,
      2006 for us. This FSP is not expected to have a material impact on our financial
      statements.





*SFAS
      151,
“Inventory Costs - an amendment of ARB No. 43, Chapter 4”*





In
      November 2004,
      the FASB issued SFAS 151 to clarify the accounting for abnormal amounts of
      idle facility expense, freight, handling costs and wasted material (spoilage).
      Previous guidance stated that in some circumstances these costs may be “so
      abnormal” that they would require treatment as current period costs.
      SFAS 151 requires abnormal amounts for these items to always be recorded as
      current period costs. In addition, this Statement requires that allocation
      of
      fixed production overheads to the cost of conversion be based on the normal
      capacity of the production facilities. The provisions of this statement are
      effective for inventory costs incurred beginning January 1, 2006. We do not
      expect this statement to have a material impact on the financial
      statements.






18





**THE
                CLEVELAND ELECTRIC ILLUMINATING
                COMPANY****CONSOLIDATED
                STATEMENTS OF INCOME****For
                the Years Ended December 31,**
            
            **2005**
            
            **2004**
            
            **2003*****(In
                thousands)*****OPERATING
                REVENUES (Note 2(I))**
            
            $
            1,868,161
            
            $
            1,808,485
            
            $
            1,719,739**OPERATING
                EXPENSES AND TAXES:**Fuel
            
            
            85,993
            
            
            78,072
            
            
            55,031Purchased
                power (Note 2(I))
            
            
            557,593
            
            
            543,949
            
            
            538,785Nuclear
                operating costs
            
            
            142,698
            
            
            117,091
            
            
            240,971Other
                operating costs (Note 2(I))
            
            
            301,366
            
            
            272,303
            
            
            236,359Provision
                for
                depreciation
            
            
            127,959
            
            
            131,854
            
            
            125,467Amortization
                of regulatory assets
            
            
            227,221
            
            
            196,501
            
            
            166,343Deferral
                of
                new regulatory assets
            
            
            (163,245
            )
            
            (117,466
            )
            
            (93,503
            )General
                taxes
            
            
            152,678
            
            
            146,276
            
            
            136,434Income
                taxes
            
            
            127,046
            
            
            111,996
            
            
            58,237Total
                operating expenses and taxes
            
            
            1,559,309
            
            
            1,480,576
            
            
            1,464,124**OPERATING
                INCOME**
            
            
            308,852
            
            
            327,909
            
            
            255,615**OTHER
                INCOME (net of income taxes) (Notes 2(I) and 7)**
            
            
            51,899
            
            
            42,190
            
            
            97,318**NET
                INTEREST CHARGES:**Interest
                on
                long-term debt
            
            
            110,419
            
            
            120,058
            
            
            157,967Allowance
                for
                borrowed funds used during construction
            
            
            (2,533
            )
            
            (5,110
            )
            
            (8,232
            )Other
                interest
                expense
            
            
            21,807
            
            
            18,620
            
            
            1,665Subsidiary's
                preferred stock dividend requirements
            
            
            -
            
            
            -
            
            
            4,500Net
                interest
                charges
            
            
            129,693
            
            
            133,568
            
            
            155,900**INCOME
                BEFORE CUMULATIVE EFFECT****OF
                ACCOUNTING CHANGES**
            
            
            231,058
            
            
            236,531
            
            
            197,033Cumulative
                effect of accounting changes (net of income taxes(benefit)
                of
                ($2,101,000) and $30,168,000, respectively) (Note 2(G))
            
            
            (3,724
            )
            
            -
            
            
            42,378**NET
                INCOME**
            
            
            227,334
            
            
            236,531
            
            
            239,411**PREFERRED
                STOCK DIVIDEND REQUIREMENTS**
            
            
            2,918
            
            
            7,008
            
            
            7,526**EARNINGS
                ON COMMON STOCK**
            
            $
            224,416
            
            $
            229,523
            
            $
            231,885The
                accompanying Notes to Consolidated Financial Statements are an integral
                part of these statements.





19







**THE
                  CLEVELAND ELECTRIC ILLUMINATING COMPANY****CONSOLIDATED
                  BALANCE SHEETS****As
                  of
                  December 31,**
              
              **2005**
              
              **2004*****(In
                  thousands)*****ASSETS****UTILITY
                  PLANT:**In
                  service
              
              $
              2,030,935
              
              $
              4,418,313Less
                  -
                  Accumulated provision for depreciation
              
              
              788,967
              
              
              1,961,7371,241,968
              
              
              2,456,576Construction
                  work in progress-Electric
                  plant
              
              
              51,129
              
              
              85,258Nuclear
                  fuel
              
              
              -
              
              
              30,82751,129
              
              
              116,0851,293,097
              
              
              2,572,661**OTHER
                  PROPERTY AND INVESTMENTS:**Investment
                  in
                  lessor notes (Note 6)
              
              
              564,166
              
              
              596,645Nuclear
                  plant
                  decommissioning trusts
              
              
              -
              
              
              383,875Long-term
                  notes receivable from associated companies
              
              
              1,076,715
              
              
              97,489Other
              
              
              12,840
              
              
              17,0011,653,721
              
              
              1,095,010**CURRENT
                  ASSETS:**Cash
                  and cash
                  equivalents
              
              
              207
              
              
              197Receivables-Customers
                  (less accumulated provision of $5,180,000 for uncollectible accounts
                  in
                  2005)
              
              
              268,427
              
              
              11,537Associated
                  companies
              
              
              86,564
              
              
              33,414Other
              
              
              16,466
              
              
              152,785Notes
                  receivable from associated companies
              
              
              -
              
              
              521Materials
                  and
                  supplies, at average cost
              
              
              -
              
              
              58,922Prepayments
                  and other
              
              
              1,903
              
              
              2,136373,567
              
              
              259,512**DEFERRED
                  CHARGES AND OTHER ASSETS:**Goodwill
              
              
              1,688,966
              
              
              1,693,629Regulatory
                  assets
              
              
              862,193
              
              
              943,898Prepaid
                  pension costs
              
              
              139,012
              
              
              -Property
                  taxes
              
              
              63,500
              
              
              77,792Other
              
              
              27,614
              
              
              32,8752,781,285
              
              
              2,748,194$
              6,101,670
              
              $
              6,675,377**CAPITALIZATION
                  AND LIABILITIES****CAPITALIZATION
                  (See Consolidated Statements of Capitalization):**Common
                  stockholder's equity
              
              $
              1,942,074
              
              $
              1,853,561Preferred
                  stock
              
              
              -
              
              
              96,404Long-term
                  debt
                  and other long-term obligations
              
              
              1,939,300
              
              
              1,970,1173,881,374
              
              
              3,920,082**CURRENT
                  LIABILITIES:**Currently
                  payable long-term debt
              
              
              75,718
              
              
              76,701Short-term
                  borrowings-Associated
                  companies
              
              
              212,256
              
              
              488,633Other
              
              
              140,000
              
              
              -Accounts
                  payable-Associated
                  companies
              
              
              74,993
              
              
              150,141Other
              
              
              4,664
              
              
              9,271Accrued
                  taxes
              
              
              121,487
              
              
              129,454Accrued
                  interest
              
              
              18,886
              
              
              22,102Lease
                  market
                  valuation liability
              
              
              60,200
              
              
              60,200Other
              
              
              61,308
              
              
              61,131769,512
              
              
              997,633**NONCURRENT
                  LIABILITIES:**Accumulated
                  deferred income taxes
              
              
              554,828
              
              
              540,211Accumulated
                  deferred investment tax credits
              
              
              23,908
              
              
              60,901Lease
                  market
                  valuation liability
              
              
              608,000
              
              
              668,200Asset
                  retirement obligation
              
              
              8,024
              
              
              272,123Retirement
                  benefits
              
              
              83,414
              
              
              82,306Deferred
                  revenues - electric service programs
              
              
              71,261
              
              
              17,814Other
              
              
              101,349
              
              
              116,1071,450,784
              
              
              1,757,662**COMMITMENTS
                  AND CONTINGENCIES (Notes 5 and 13)**$
              6,101,670
              
              $
              6,675,377The
                  accompanying Notes to Consolidated Financial Statements are an
                  integral
                  part of these balance sheets.
   20
  **THE
                  CLEVELAND ELECTRIC ILLUMINATING COMPANY****CONSOLIDATED
                  STATEMENTS OF CAPITALIZATION****As
                  of
                  December 31,**
              
              
              **2005**
              
              **2004*****(Dollars
                  in thousands, except per share amounts)*****COMMON
                  STOCKHOLDER'S EQUITY:**Common
                  stock,
                  without par value, authorized 105,000,000 shares
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              $
              1,354,924
              
              $
              1,281,96279,590,689
                  shares outstandingAccumulated
                  other comprehensive income (Note 2(F))
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              -
              
              
              17,859Retained
                  earnings (Note 10(A))
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              587,150
              
              
              553,740Total
                  common
                  stockholder's equity
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              1,942,074
              
              
              1,853,561**Number
                  of Shares****Outstanding**
              
              
              **Optional**
                **Redemption
                  Price****2005**
              
              
              **2004**
              
              
              **Per
                  Share**
              
              
              **Aggregate****PREFERRED
                  STOCK NOT SUBJECT TO****MANDATORY
                  REDEMPTION (Note 10(B)):**Cumulative,
                  without par value-Authorized
                  4,000,000 shares$
                  7.40 Series
                  A
              
              
              -
              
              
              500,000
              
              
              
              
              $
              -
              
              
              
              
              -
              
              
              50,000Adjustable
                  Series L
              
              
              -
              
              
              474,000
              
              
              
              
              
              -
              
              
              
              
              -
              
              
              46,404Total
              
              
              -
              
              
              974,000
              
              
              
              
              $
              -
              
              
              
              
              -
              
              
              96,404**LONG-TERM
                  DEBT AND OTHER****LONG-TERM
                  OBLIGATIONS (Note 10(C)):**First
                  mortgage
                  bonds:6.860%
                  due
                  2008
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              125,000
              
              
              125,000Total
                  first
                  mortgage bonds
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              125,000
              
              
              125,000Secured
                  notes:7.000%
                  due
                  2005-2009
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              -
              
              
              1,7007.130%
                  due
                  2007
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              120,000
              
              
              120,0007.430%
                  due
                  2009
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              150,000
              
              
              150,000* 
3.150%
                  due 2015
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              39,835
              
              
              39,8357.880%
                  due
                  2017
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              300,000
              
              
              300,000* 
3.150%
                  due 2018
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              72,795
              
              
              72,795* 
3.580%
                  due 2020
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              47,500
              
              
              47,5006.000%
                  due
                  2020
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              62,560
              
              
              62,5606.100%
                  due
                  2020
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              70,500
              
              
              70,5007.625%
                  due
                  2025
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              -
              
              
              53,9007.700%
                  due
                  2025
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              -
              
              
              43,8007.750%
                  due
                  2025
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              -
              
              
              45,1505.375%
                  due
                  2028
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              5,993
              
              
              5,993* 
3.350%
                  due 2030
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              23,255
              
              
              23,255* 
3.750%
                  due 2030
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              81,640
              
              
              81,640* 
3.150%
                  due 2033
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              30,000
              
              
              30,000* 
3.150%
                  due 2033
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              46,100
              
              
              46,100* 
3.050%
                  due 2034
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              40,900
              
              
              -* 
3.500%
                  due 2034
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              2,900
              
              
              -* 
3.350%
                  due 2035
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              53,900
              
              
              -* 
3.500%
                  due 2035
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              45,150
              
              
              -Total
                  secured
                  notes
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              1,193,028
              
              
              1,194,728Unsecured
                  notes:6.000%
                  due
                  2013
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              78,700
              
              
              78,7005.650%
                  due
                  2013
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              300,000
              
              
              300,0009.000%
                  due
                  2031
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              103,093
              
              
              103,093*3.670%
                  due 2033
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              27,700
              
              
              27,700509,493
              
              
              509,4937.742%
                  due to
                  associated companies 2007-2016 (Note 6)
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              176,847
              
              
              188,629Total
                  unsecured notes
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              686,340
              
              
              698,122Preferred
                  stock subject to mandatory redemption
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              -
              
              
              4,009Capital
                  lease
                  obligations (Note 5)
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              4,939
              
              
              5,455Net
                  unamortized premium on debt
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              5,711
              
              
              19,504Long-term
                  debt
                  due within one year
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              (75,718
              )
              
              (76,701
              )Total
                  long-term debt and other long-term obligations
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              1,939,300
              
              
              1,970,117**TOTAL
                  CAPITALIZATION**
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              $
              3,881,374
              
              $
              3,920,082*
                  Denotes
                  variable rate issue with December 31, 2005 interest rate
                  shown.The
                  accompanying Notes to Consolidated Financial Statements are an
                  integral
                  part of these statements.
    21
   **THE
                    CLEVELAND ELECTRIC ILLUMINATING COMPANY****CONSOLIDATED
                    STATEMENTS OF COMMON STOCKHOLDER'S EQUITY****Accumulated****Other****Comprehensive**
                
                **Number**
                
                **Carrying**
                
                **Comprehensive**
                
                **Retained****Income**
                
                **of
                    Shares**
                
                **Value**
                
                **Income
                    (Loss)**
                
                **Earnings*****(Dollars
                    in thousands)***Balance,
                    January 1, 2003
                
                
                
                
                
                79,590,689
                
                $
                981,962
                
                $
                (44,284
                )
                $
                262,323Net
                    income
                
                $
                239,411
                
                
                
                
                
                
                
                
                
                
                
                239,411Unrealized
                    gain on investments, net of$19,598,000
                    of
                    income taxes
                
                
                28,255
                
                
                
                
                
                
                
                
                28,255Minimum
                    liability for unfunded retirement benefits,net
                    of
                    $13,760,000 of income taxes
                
                
                18,682
                
                
                
                
                
                
                
                
                18,682Comprehensive
                    income
                
                $
                286,348Equity
                    contribution from parent
                
                
                
                
                
                
                
                
                300,000Cash
                    dividends
                    on preferred stock
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                (7,429
                )Preferred
                    stock redemption premiums
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                (93
                )Balance,
                    December 31, 2003
                
                
                
                
                
                79,590,689
                
                
                1,281,962
                
                
                2,653
                
                
                494,212Net
                    income
                
                $
                236,531
                
                
                
                
                
                
                
                
                
                
                
                236,531Unrealized
                    gain on investments, net of$8,294,000
                    of
                    income taxes
                
                
                11,450
                
                
                
                
                
                
                
                
                11,450Minimum
                    liability for unfunded retirement benefits,net
                    of
                    $2,413,000 of income taxes
                
                
                3,756
                
                
                
                
                
                
                
                
                3,756Comprehensive
                    income
                
                $
                251,737Cash
                    dividends
                    on preferred stock
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                (7,003
                )Cash
                    dividends
                    on common stock
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                (170,000
                )Balance,
                    December 31, 2004
                
                
                
                
                
                79,590,689
                
                
                1,281,962
                
                
                17,859
                
                
                553,740Net
                    income
                
                $
                227,334
                
                
                
                
                
                
                
                
                
                
                
                227,334Unrealized
                    loss on investments, net of$(27,734,000)
                    of income taxes
                
                
                (39,472
                )
                
                
                
                
                
                
                
                (39,472
                )Minimum
                    liability for unfunded retirement benefits,net
                    of
                    $15,186,000 of income taxes
                
                
                21,613
                
                
                
                
                
                
                
                
                21,613Comprehensive
                    income
                
                $
                209,475Equity
                    contribution from parent
                
                
                
                
                
                
                
                
                75,000Affiliated
                    company asset transfers
                
                
                
                
                
                
                
                
                (2,086
                )Restricted
                    stock units
                
                
                
                
                
                
                
                
                48Cash
                    dividends
                    on preferred stock
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                (2,924
                )Cash
                    dividends
                    on common stock
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                (191,000
                )Balance,
                    December 31, 2005
                
                
                
                
                
                79,590,689
                
                $
                1,354,924
                
                $
                -
                
                $
                587,150
   **CONSOLIDATED
                    STATEMENTS OF PREFERRED STOCK****Not
                    Subject to**
                
                **Subject
                    to****Mandatory
                    Redemption**
                
                **Mandatory
                    Redemption*****Number**
                
                **Carrying**
                
                **Number**
                
                **Carrying****of
                    Shares**
                
                **Value**
                
                **of
                    Shares**
                
                **Value*****(Dollars
                    in thousands)***Balance,
                    January 1, 2003
                
                
                974,000
                
                $
                96,404
                
                
                4,060,000
                
                $
                106,021Redemptions-$7.35
                    Series
                    C
                
                
                
                
                
                
                
                
                (10,000
                )
                
                (1,000
                )FIN
                    46
                    Deconsolidation-9.00%
                    Series
                
                
                
                
                
                
                
                
                (4,000,000
                )
                
                (100,000
                )Amortization
                    of fair marketvalue
                    adjustments-$7.35
                    Series
                    C
                
                
                
                
                
                
                
                
                
                
                
                (7
                )Balance,
                    December 31, 2003
                
                
                974,000
                
                
                96,404
                
                
                50,000
                
                
                5,014Redemptions-$7.35
                    Series
                    C
                
                
                
                
                
                
                
                
                (10,000
                )
                
                (1,000
                )Amortization
                    of fair marketvalue
                    adjustments-$7.35
                    Series
                    C
                
                
                
                
                
                
                
                
                
                
                
                (5
                )Balance,
                    December 31, 2004
                
                
                974,000
                
                
                96,404
                
                
                40,000
                
                
                4,009Redemptions-$7.40
                    Series
                    A
                
                
                (500,000
                )
                
                (50,000
                )Adjustable
                    Series L
                
                
                (474,000
                )
                
                (46,404
                )$7.35
                    Series
                    C
                
                
                
                
                
                
                
                
                (40,000
                )
                
                (4,000
                )Amortization
                    of fair marketvalue
                    adjustments-$7.35
                    Series
                    C
                
                
                
                
                
                
                
                
                
                
                
                (9
                )Balance,
                    December 31, 2005
                
                
                -
                
                $
                -
                
                
                -
                
                $
                -*
                    Preferred
                    stock subject to mandatory redemption is classified as debt under
                    SFAS
                    150.The
                    accompanying Notes to Consolidated Financial Statements are an
                    integral
                    part of these statements.
   22
  
 **THE
                    CLEVELAND ELECTRIC ILLUMINATING COMPANY****CONSOLIDATED
                    STATEMENTS OF CASH FLOWS****For
                    the Years Ended December 31,**
                
                **2005**
                
                **2004**
                
                **2003*****(In
                    thousands)*****CASH
                    FLOWS FROM OPERATING ACTIVITIES:**Net
                    income
                
                $
                227,334
                
                $
                236,531
                
                $
                239,411Adjustments
                    to
                    reconcile net income to net cash fromoperating
                    activities -Provision
                    for
                    depreciation
                
                
                127,959
                
                
                131,854
                
                
                125,467Amortization
                    of regulatory assets
                
                
                227,221
                
                
                196,501
                
                
                166,343Deferral
                    of
                    new regulatory assets
                
                
                (163,245
                )
                
                (117,466
                )
                
                (93,503
                )Nuclear
                    fuel
                    and capital lease amortization
                
                
                25,803
                
                
                28,239
                
                
                17,466Deferred
                    rents
                    and lease market valuation liability
                
                
                (67,353
                )
                
                (56,405
                )
                
                (78,214
                )Deferred
                    income taxes and investment tax credits, net
                
                
                42,024
                
                
                39,129
                
                
                (7,836
                )Accrued
                    compensation and retirement benefits
                
                
                4,624
                
                
                15,678
                
                
                (1,113
                )Cumulative
                    effect of accounting changes
                
                
                3,724
                
                
                -
                
                
                (42,378
                )Pension
                    trust
                    contribution
                
                
                (93,269
                )
                
                (31,718
                )
                
                -Tax
                    refund
                    related to pre-merger period
                
                
                9,636
                
                
                -
                
                
                -Decrease
                    (increase) in operating assets-Receivables
                
                
                (103,018
                )
                
                38,297
                
                
                (16,339
                )Materials
                    and
                    supplies
                
                
                (12,934
                )
                
                (8,306
                )
                
                5,771Prepayments
                    and other current assets
                
                
                233
                
                
                2,375
                
                
                (294
                )Increase
                    (decrease) in operating liabilities-Accounts
                    payable
                
                
                (82,434
                )
                
                (93,745
                )
                
                (54,858
                )Accrued
                    taxes
                
                
                (7,967
                )
                
                (73,068
                )
                
                76,261Accrued
                    interest
                
                
                (3,216
                )
                
                (15,770
                )
                
                (13,895
                )Electric
                    service prepayment programs
                
                
                53,447
                
                
                (18,386
                )
                
                (16,278
                )Other
                
                
                (40,878
                )
                
                (51,617
                )
                
                4,754Net
                    cash
                    provided from operating activities
                
                
                147,691
                
                
                222,123
                
                
                310,765**CASH
                    FLOWS FROM FINANCING ACTIVITIES:**New
                    Financing-Long-term
                    debt
                
                
                141,004
                
                
                124,977
                
                
                296,905Short-term
                    borrowings, net
                
                
                155,883
                
                
                290,263
                
                
                -Equity
                    contributions from parent
                
                
                75,000
                
                
                -
                
                
                300,000Redemptions
                    and Repayments-Preferred
                    stock
                
                
                (101,900
                )
                
                (1,000
                )
                
                (1,093
                )Long-term
                    debt
                
                
                (147,923
                )
                
                (335,393
                )
                
                (677,097
                )Short-term
                    borrowings, net
                
                
                -
                
                
                -
                
                
                (109,212
                )Dividend
                    Payments-Common
                    stock
                
                
                (191,000
                )
                
                (170,000
                )
                
                -Preferred
                    stock
                
                
                (2,260
                )
                
                (7,008
                )
                
                (7,451
                )Net
                    cash used
                    for financing activities
                
                
                (71,196
                )
                
                (98,161
                )
                
                (197,948
                )**CASH
                    FLOWS FROM INVESTING ACTIVITIES:**Property
                    additions
                
                
                (148,783
                )
                
                (121,316
                )
                
                (134,899
                )Loan
                    repayments from (loans to) associated companies, net
                
                
                (387,746
                )
                
                9,936
                
                
                (5,450
                )Collection
                    of
                    principal on long-term notes receivable
                
                
                466,378
                
                
                482
                
                
                447Investments
                    in
                    lessor notes
                
                
                32,479
                
                
                9,270
                
                
                44,732Contributions
                    to nuclear decommissioning trusts
                
                
                (29,024
                )
                
                (29,024
                )
                
                (29,024
                )Other
                
                
                (9,789
                )
                
                (17,895
                )
                
                5,777Net
                    cash used
                    for investing activities
                
                
                (76,485
                )
                
                (148,547
                )
                
                (118,417
                )Net
                    increase
                    (decrease) in cash and cash equivalents
                
                
                10
                
                
                (24,585
                )
                
                (5,600
                )Cash
                    and cash
                    equivalents at beginning of year
                
                
                197
                
                
                24,782
                
                
                30,382Cash
                    and cash
                    equivalents at end of year
                
                $
                207
                
                $
                197
                
                $
                24,782**SUPPLEMENTAL
                    CASH FLOW INFORMATION:**Cash
                    Paid
                    During the Year-Interest
                    (net
                    of amounts capitalized)
                
                $
                144,730
                
                $
                152,373
                
                $
                174,375Income
                    taxes
                
                $
                116,323
                
                $
                144,277
                
                $
                24,796The
                    accompanying Notes to Consolidated Financial Statements are an
                    integral
                    part of these statements.
   23
   **THE
                    CLEVELAND ELECTRIC ILLUMINATING
                    COMPANY****CONSOLIDATED
                    STATEMENTS OF TAXES****For
                    the Years Ended December 31,**
                
                
                
                **2005**
                
                **2004**
                
                **2003*****(In
                    thousands)*****GENERAL
                    TAXES:**Real
                    and
                    personal property
                
                
                
                
                $
                77,822
                
                $
                74,206
                
                $
                63,448Ohio
                    kilowatt-hour excise*
                
                
                
                
                
                68,950
                
                
                66,974
                
                
                68,459Social
                    security and unemployment
                
                
                
                
                
                5,282
                
                
                4,496
                
                
                4,331Other
                
                
                
                
                
                624
                
                
                600
                
                
                196Total
                    general
                    taxes
                
                
                
                
                $
                152,678
                
                $
                146,276
                
                $
                136,434**PROVISION
                    FOR INCOME TAXES:**Currently
                    payable-Federal
                
                
                
                
                $
                88,147
                
                $
                72,264
                
                $
                109,775State
                
                
                
                
                
                22,843
                
                
                27,463
                
                
                29,346110,990
                
                
                99,727
                
                
                139,121Deferred,
                    net-Federal
                
                
                
                
                
                28,310
                
                
                34,450
                
                
                21,382State
                
                
                
                
                
                16,350
                
                
                9,775
                
                
                5,75744,660
                
                
                44,225
                
                
                27,139Investment
                    tax
                    credit amortization
                
                
                
                
                
                (4,737
                )
                
                (5,096
                )
                
                (4,807
                )Total
                    provision for income taxes
                
                
                
                
                $
                150,913
                
                $
                138,856
                
                $
                161,453**INCOME
                    STATEMENT CLASSIFICATION****OF
                    PROVISION FOR INCOME TAXES:**Operating
                    income
                
                
                
                
                $
                127,046
                
                $
                111,996
                
                $
                58,237Other
                    income
                
                
                
                
                
                25,968
                
                
                26,860
                
                
                73,048Cumulative
                    effect of accounting changes
                
                
                
                
                
                (2,101
                )
                
                -
                
                
                30,168Total
                    provision for income taxes
                
                
                
                
                $
                150,913
                
                $
                138,856
                
                $
                161,453**RECONCILIATION
                    OF FEDERAL INCOME TAX****EXPENSE
                    AT STATUTORY RATE TO TOTAL****PROVISION
                    FOR INCOME TAXES:**Book
                    income
                    before provision for income taxes
                
                
                
                
                $
                378,247
                
                $
                375,387
                
                $
                400,864Federal
                    income
                    tax expense at statutory rate
                
                
                
                
                $
                132,387
                
                $
                131,385
                
                $
                140,302Increases
                    (reductions) in taxes resulting from-State
                    income
                    taxes, net of federal income tax benefit
                
                
                
                
                
                25,475
                
                
                24,205
                
                
                22,817Amortization
                    of investment tax credits
                
                
                
                
                
                (4,737
                )
                
                (5,096
                )
                
                (4,807
                )Other,
                    net
                
                
                
                
                
                (2,212
                )
                
                (11,638
                )
                
                3,141Total
                    provision for income taxes
                
                
                
                
                $
                150,913
                
                $
                138,856
                
                $
                161,453**ACCUMULATED
                    DEFERRED INCOME TAXES AS OF****DECEMBER
                    31:**Property
                    basis
                    differences
                
                
                
                
                $
                498,079
                
                $
                502,625
                
                $
                477,358Regulatory
                    transition charge
                
                
                
                
                
                159,535
                
                
                221,386
                
                
                302,270Asset
                    retirement obligations
                
                
                
                
                
                -
                
                
                24,638
                
                
                23,086Unamortized
                    investment tax credits
                
                
                
                
                
                (10,150
                )
                
                (23,208
                )
                
                (25,311
                )Deferred
                    gain
                    for asset sales- affiliated companies
                
                
                
                
                
                33,329
                
                
                33,841
                
                
                38,394Other
                    comprehensive income
                
                
                
                
                
                -
                
                
                12,548
                
                
                1,841Above
                    market
                    leases
                
                
                
                
                
                (256,297
                )
                
                (300,000
                )
                
                (324,843
                )Retirement
                    benefits
                
                
                
                
                
                12,005
                
                
                (21,674
                )
                
                (32,023
                )Shopping
                    incentive deferral
                
                
                
                
                
                153,750
                
                
                121,778
                
                
                73,804Other
                
                
                
                
                
                (35,423
                )
                
                (31,723
                )
                
                (48,528
                )Net
                    deferred
                    income tax liability
                
                
                
                
                $
                554,828
                
                $
                540,211
                
                $
                486,048*Collected
                    from customers through regulated rates and included in revenue
                    in the
                    Consolidated Statements of Income.The
                    accompanying Notes to Consolidated Financial Statements are an
                    integral
                    part of these statements.


24





**NOTES
      TO
      CONSOLIDATED FINANCIAL STATEMENTS**





**1.**  **ORGANIZATION
      AND BASIS OF PRESENTATION:**




The
        consolidated
        financial statements include CEI (Company) and its wholly owned subsidiaries,
        CFC and Shippingport (see Note 6).
        The
        Company is a wholly owned subsidiary of FirstEnergy. FirstEnergy also holds
        directly all of the issued and outstanding common shares of its other principal
        electric utility operating subsidiaries, including OE, TE, ATSI, JCP&L,
        Met-Ed and Penelec. In the fourth quarter of 2005, the Company completed
        the
        intra-system transfers of its non-nuclear and nuclear generation assets to
        FGCO
        and NGC, respectively. See Note 14 - FirstEnergy Intra-System Generation
        Asset Transfers for further discussion.
 
 The
        Company follows
        GAAP and complies with the regulations, orders, policies and practices
        prescribed by the SEC, PUCO and the FERC. 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 the disclosure of contingent assets
        and
        liabilities. Actual results could differ from these estimates.
 
 The
        Company
        consolidates all majority-owned subsidiaries over which the Company exercises
        control and, when applicable, entities for which the Company has a controlling
        financial interest. Intercompany transactions and balances are eliminated
        in
        consolidation. Investments in non-consolidated affiliates (20-50% owned
        companies, joint ventures and partnerships) over which the Company has the
        ability to exercise significant influence, but not control, are accounted
        for on
        the equity basis.
 
 Unless
        otherwise
        indicated, defined terms used herein have the meanings set forth in the
        accompanying Glossary of Terms.




**2.**  **SUMMARY
      OF
      SIGNIFICANT ACCOUNTING POLICIES:**





**(A)**  **ACCOUNTING
      FOR THE EFFECTS OF REGULATION-**




The
        Company accounts
        for the effects of regulation through the application of SFAS 71
        since its
        rates:
  ·  are
        established by a
        third-party regulator with the authority to set rates that bind
        customers;





·  are
      cost-based;
      and





·  can
      be charged to
      and collected from customers.





An
      enterprise
      meeting all of these criteria capitalizes costs that would otherwise be charged
      to expense if the rate actions of its regulator make it probable that those
      costs will be recovered in future revenue. SFAS 71 is applied only to the
      parts of the business that meet the above criteria. If a portion of the business
      applying SFAS 71 no longer meets those requirements, previously recorded
      regulatory assets are removed from the balance sheet in accordance with the
      guidance in SFAS 101.





*Regulatory
      Assets-*





The
      Company
      recognizes, as regulatory assets, costs which the FERC and the PUCO have
      authorized for recovery from customers in future periods or for which
      authorization is probable. Without the probability of such authorization, costs
      currently recorded as regulatory assets would have been charged to income as
      incurred. All regulatory assets are expected to be recovered from customers
      under the Company’s transition plan. Based on that plan, the Company continues
      to bill and collect cost-based rates for its transmission and distribution
      services, which will remain regulated; accordingly, it is appropriate that
      the
      Company continues the application of SFAS 71 to those
      operations.





Net
      regulatory
      assets on the Consolidated Balance Sheets are comprised of the
      following:





**2005**
            
            **2004*****(In
                millions)***Regulatory
                transition costs
            
            $
            479
            
            $
            705Customer
                shopping incentives
            
            
            427
            
            
            295Employee
                postretirement benefit costs
            
            
            12
            
            
            13Asset
                removal
                costs
            
            
            (90
            )
            
            (75
            )MISO
                transmission costs
            
            
            30
            
            
            -Other
            
            
            4
            
            
            6Total
            
            $
            862
            
            $
            944




25


The
      Company has been
      deferring customer shopping incentives and interest costs (Extended RTC) as
      new
      regulatory assets in accordance with the prior transition and rate stabilization
      plans. As a result of the RCP approved in January 2006, the Extended RTC balance
      ($427 million as of December 31, 2005) was reduced on January 1,
      2006 by $85 million by accelerating the application of the Company's
      accumulated cost of removal regulatory liability against the Extended RTC
      balance. In accordance with the RCP, the recovery periods for the aggregate
      of
      the regulatory transition costs and the Extended RTC amounts were adjusted
      so
      that recovery of these aggregate amounts through the Company's RTC rate
      component began on January 1, 2006. The Company's recovery of its RTC is
      projected to be completed by April 2009 at which time recovery of its Extended
      RTC will begin, with recovery estimated to be completed as of December 31,
      2010. At the end of the recovery period, any remaining unamortized regulatory
      transition costs and Extended RTC balances will be eliminated, first, by
      applying any remaining cost of removal regulatory liability balance. Any
      remaining regulatory transition costs and Extended RTC balances would be written
      off. In addition, the RCP allowed the Ohio Companies to defer and capitalize
      certain distribution costs during the period January 1, 2006 through
      December 31, 2008, not to exceed $150 million in each of the years
      2006, 2007 and 2008. These deferrals will be recovered in distribution rates
      effective on or after January 1, 2009. See Note 9 for further
      discussion of the recovery of the shopping incentives and the new cost
      deferrals.





*Transition
      Cost
      Amortization-*





The
      Company
      amortizes transition costs (see Regulatory Matters - Ohio) using the effective
      interest method. Extended RTC amortization will be equal to the related revenue
      recovery that is recognized. The following table provides the estimated net
      amortization of regulatory transition costs and Extended RTC (including
      associated carrying charges) under the RCP for the period 2006 through
      2010:





**Amortization****Period**
            
            **Amortization*****(In
                millions)***2006
            
            $
            1002007
            
            
            1112008
            
            
            1292009
            
            
            2162010
            
            
            268**Total
                Amortization**
            
            **$**
            **824**





**(B)**  **CASH
      AND
      SHORT-TERM FINANCIAL INSTRUMENTS-**





All
      temporary cash
      investments purchased with an initial maturity of three months or less are
      reported as cash equivalents on the Consolidated Balance Sheets at cost, which
      approximates their fair market value.





**(C)**  **REVENUES
      AND
      RECEIVABLES-**





The
      Company's
      principal business is providing electric service to customers in Ohio. The
      Company's retail customers are metered on a cycle basis. Electric revenues
      are
      recorded based on energy delivered through the end of the calendar month. An
      estimate of unbilled revenues is calculated to recognize electric service
      provided between the last meter reading and the end of the month. This estimate
      includes many factors including estimated weather impacts, customer shopping
      activity, historical line loss factors and prices in effect for each class
      of
      customer. In each accounting period, the Company accrues the estimated unbilled
      amount receivable as revenue and reverses the related prior period
      estimate.





Receivables
      from
      customers include sales to residential, commercial and industrial customers
      located in the Company's service area and sales to wholesale customers. There
      was no material concentration of receivables as of December 31, 2005, with
      respect to any particular segment of the Company's customers. Total customer
      receivables were $268 million (billed - $157 million and unbilled -
      $111 million) and $12 million (billed - $9 million and unbilled -
      $3 million) as of December 31, 2005 and 2004,
      respectively.





The
      Company and TE
      sell substantially all of their retail customer receivables to CFC. In June
      2005, the CFC receivables financing structure was renewed and restructured
      from
      an off-balance sheet transition to an on-balance sheet transaction. Under the
      new structure, any borrowings under the facility appear on the balance sheet
      as
      short-term debt.





**(D)**  **UTILITY
      PLANT AND DEPRECIATION-**





Utility
      plant
      reflects original cost of construction (except for the Company's nuclear
      leasehold interests which were adjusted to fair value), including payroll and
      related costs such as taxes, employee benefits, administrative and general
      costs, and interest costs incurred to place the assets in service. The costs
      of
      normal maintenance, repairs and minor replacements are expensed as incurred.
      The
      Company's accounting policy for planned major maintenance projects is to
      recognize liabilities as they are incurred.


26


The
      Company provides
      for depreciation on a straight-line basis at various rates over the estimated
      lives of property included in plant in service. The annualized composite rate
      was approximately 2.9% in 2005, 2.8% in 2004, and 2.8% in 2003.





**(E)**  **ASSET
      IMPAIRMENTS-**





*Long-Lived
      Assets-*





The
      Company
      evaluates the carrying value of its long-lived assets when events or
      circumstances indicate that the carrying amount may not be recoverable. In
      accordance with SFAS 144, the carrying amount of a long-lived asset is not
      recoverable if it exceeds the sum of the undiscounted cash flows expected to
      result from the use and eventual disposition of the asset. If an impairment
      exists, a loss is recognized for the amount by which the carrying value of
      the
      long-lived asset exceeds its estimated fair value. Fair value is estimated
      by
      using available market valuations or the long-lived asset's expected future
      net
      discounted cash flows. The calculation of expected cash flows is based on
      estimates and assumptions about future events.





*Goodwill-*





In
      a business
      combination, the excess of the purchase price over the estimated fair values
      of
      assets acquired and liabilities assumed is recognized as goodwill. Based on
      the
      guidance provided by SFAS 142, the Company evaluates its goodwill for
      impairment at least annually and would make such an evaluation more frequently
      if indicators of impairment should arise. In accordance with the accounting
      standard, if the fair value of a reporting unit is less than its carrying value
      (including goodwill), the goodwill is tested for impairment. If an impairment
      is
      indicated, the Company recognizes a loss - calculated as the difference between
      the implied fair value of a reporting unit's goodwill and the carrying value
      of
      the goodwill. The Company's 2005 annual review was completed in the third
      quarter of 2005 with no impairment indicated. The forecasts used in the
      Company's evaluation of goodwill reflect operations consistent with its general
      business assumptions. Unanticipated changes in those assumptions could have
      a
      significant effect on its future evaluations of goodwill. As of
      December 31, 2005, the Company had approximately $1.7 billion of
      goodwill. In the year ended December 31, 2005, the Company adjusted
      goodwill to reverse pre-merger tax accruals due to the final resolution of
      tax
      contingencies related to the Centerior acquisition. The impairment analysis
      includes a significant source of cash representing the Company's recovery of
      transition costs as described below under "Regulatory Matters." The Company
      estimates that completion of transition cost recovery will not result in an
      impairment of goodwill.





**(F)**  **COMPREHENSIVE
      INCOME-**





Comprehensive
      income
      includes net income as reported on the Consolidated Statements of Income and
      all
      other changes in common stockholder's equity except those resulting from
      transactions with FirstEnergy and preferred stockholders. As of
      December 31, 2005, the Company does not have an accumulated other
      comprehensive balance. As of December 31, 2004, accumulated other
      comprehensive income consisted of a minimum liability for unfunded retirement
      benefits of $22 million and unrealized gains on investments in securities
      available for sale of $40 million.





**(G)**  **CUMULATIVE
      EFFECT OF ACCOUNTING CHANGES-**





Results
      in 2005
      include an after-tax charge of $ 4 million
      recorded upon the adoption of FIN 47 in December 2005. The Company
      identified applicable legal obligations as defined under the new standard at
      its
      retired generating units, substation control rooms, service center buildings,
      line shops and office buildings, identifying asbestos as the primary conditional
      ARO. The Company recorded a conditional ARO liability of $7 million
      (including accumulated accretion for the period from the date the liability
      was
      incurred to the date of adoption), an asset retirement cost of $2 million
      (recorded as part of the carrying amount of the related long-lived asset),
      and
      accumulated depreciation of $2 million. T he
      Company charged a
      regulatory liability for $1 million upon adoption of FIN 47 for the
      transition amounts related to establishing the ARO for asbestos removal from
      substation control rooms and service center buildings. The remaining cumulative
      effect adjustment for unrecognized depreciation and accretion of $6 million
      was charged to income ($4 million, net of tax).





Results
      for 2003
      include an after-t ax
      credit to net
      income of $42 million recorded by the Company upon adoption of
      SFAS 143 in January of 2003. The Company identified applicable legal
      obligations as defined under the new accounting standard for nuclear power
      plant
      decommissioning, reclamation of a sludge disposal pond at the Bruce Mansfield
      Plant, and closure of two coal ash disposal sites. As a result of adopting
      SFAS 143 in January 2003, asset retirement costs of $50 million were
      recorded as part of the carrying amount of the related long-lived asset, offset
      by accumulated depreciation of $7 million. The asset retirement obligation
      liability at the date of adoption was $238 million, including accumulated
      accretion for the period from the date the liability was incurred to the date
      of
      adoption. As of December 31, 2002, the Company had recorded decommissioning
      liabilities of $243 million. The cumulative effect adjustment for
      unrecognized depreciation and accretion, offset by the reduction in the existing
      decommissioning liabilities and the reversal of accumulated estimated removal
      costs for non-regulated generation assets, was a $73 million increase to
      income, or $42 million net of income taxes.


27


**(H)**  **INCOME
      TAXES-**





Details
      of the total
      provision for income taxes are shown on the Consolidated Statements of Taxes.
      The Company records income taxes in accordance with the liability method of
      accounting. Deferred income taxes reflect the net tax effect of temporary
      differences between the carrying amounts of assets and liabilities for financial
      reporting purposes and the amounts used for tax purposes. Investment tax
      credits, which were deferred when utilized, are being amortized over the
      recovery period of the related property. Deferred income tax liabilities related
      to tax and accounting basis differences and tax credit carryforward items are
      recognized at the statutory income tax rates in effect when the liabilities
      are
      expected to be paid. Deferred tax assets are recognized based on income tax
      rates expected to be in effect when they are settled. The Company is included
      in
      FirstEnergy's consolidated federal income tax return. The consolidated tax
      liability is allocated on a "stand-alone" company basis, with each Company
      recognizing any tax losses or credits the Company contributes to the
      consolidated return. (See Note 8
      for Ohio Tax Legislation discussion.)





**(I)**  **TRANSACTIONS
      WITH AFFILIATED COMPANIES-**





Operating
      revenues,
      operating expenses and other income include transactions with affiliated
      companies, primarily ATSI, FES, NGC and FESC. The Ohio transition plan resulted
      in the corporate separation of FirstEnergy's regulated and unregulated
      operations in 2001. FES operates the generation businesses of the Company,
      TE,
      OE and Penn. As a result, the Company had entered into power supply agreements
      (PSA) whereby FES purchased all of the Company's nuclear generation and the
      generation from leased fossil generation facilities. In the fourth quarter
      of
      2005, the Company, TE, OE and Penn completed the intra-system transfers of
      their
      generation assets to FGCO and NGC (see Note 14). This resulted in the
      elimination of the fossil generating units rent revenues and the nuclear
      generation PSA revenues with the exception of those revenues related to the
      leasehold interests (see Note 6) which were not included in the Company's
      transfers. The Company is now receiving interest income from FGCO and NGC on
      the
      associated companies notes received in exchange for the transferred net assets.
      The Company continues to purchase its power from FES to meet its PLR
      obligations. In the fourth quarter of 2003, ATSI transferred operational control
      of its transmission facilities to MISO and previously affiliated transmission
      service expenses are now provided under the MISO Open Access Transmission
      Tariff. CFC serves as the transferor in connection with the accounts receivable
      securitization for the Company and TE. The primary affiliated company's
      transactions are as follows:








**2005**
            
            **2004**
            
            **2003*****(In
                millions)*****Operating
                Revenues:**PSA
                revenues
                from FES
            
            $
            362
            
            $
            387
            
            $
            260Generating
                units rent from FES
            
            
            49
            
            
            59
            
            
            59Ground
                lease
                with ATSI
            
            
            7
            
            
            7
            
            
            7**Services
                Received:**Purchased
                power under PSA
            
            
            452
            
            
            444
            
            
            423Purchased
                power from TE
            
            
            105
            
            
            101
            
            
            109Transmission
                expenses
            
            
            -
            
            
            -
            
            
            32FESC
                support
                services
            
            
            60
            
            
            65
            
            
            63**Other
                Income:**Interest
                income from ATSI
            
            
            1
            
            
            7
            
            
            7Interest
                income from FES and NGC
            
            
            6
            
            
            -
            
            
            1





The
        Company is
        buying 150 MW of TE's Beaver Valley Unit 2 leased capacity
        entitlement. Purchased power expenses for this transaction were
        $105 million, $101 million and $109 million in 2005, 2004 and
        2003, respectively. This purchase agreement is expected to continue through
        the
        end of the lease period (see Note 5).
 
 FirstEnergy
        does not
        bill directly or allocate any of its costs to any subsidiary company. Costs
        are
        allocated to the Company from FESC, a subsidiary of FirstEnergy. The majority
        of
        costs are directly billed or assigned at no more than cost. The remaining
        costs
        are for services that are provided on behalf of more than one company, or
        costs
        that cannot be precisely identified and are allocated using formulas developed
        by FESC. The current allocation or assignment formulas used and their bases
        include multiple factor formulas; each company's proportionate amount of
        FirstEnergy's aggregate direct payroll, number of employees, asset balances,
        revenues, number of customers, other factors and specific departmental charge
        ratios. Management believes that these allocation methods are reasonable.
        Intercompany transactions with FirstEnergy and its other subsidiaries are
        generally settled under commercial terms within thirty days.
    28


**3.**  **PENSION
      AND
      OTHER POSTRETIREMENT BENEFIT PLANS:**





FirstEnergy
      provides
      noncontributory defined benefit pension plans that cover substantially all
      of
      its employees. The trustee plans provide defined benefits based on years of
      service and compensation levels. The Company's funding policy is based on
      actuarial computations using the projected unit credit method. In the fourth
      quarter of 2005, FirstEnergy made a $500 million voluntary contribution to
      its pension plan (Company's share was $93 million). Projections indicated
      that absent this funding, cash contributions would have been required at some
      point prior to 2010. Pre-funding the pension plan is expected to eliminate
      this
      future funding requirement under current pension funding rules and should also
      minimize FirstEnergy's exposure to any funding requirements resulting from
      proposed pension reform.





FirstEnergy
      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 also available
      upon retirement to employees hired prior to January 1, 2005, their
      dependents and, under certain circumstances, their survivors. The Company
      recognizes the expected cost of providing other postretirement benefits to
      employees and their beneficiaries and covered dependents from the time employees
      are hired until they become eligible to receive those benefits. In addition,
      FirstEnergy has obligations to former or inactive employees after employment,
      but before retirement for disability related benefits.





Pension
      and OPEB
      costs are affected by employee demographics (including age, compensation levels,
      and employment periods), the level of contributions made to the plans, and
      earnings on plan assets. Such factors may be further affected by business
      combinations, which impact employee demographics, plan experience and other
      factors. Pension and OPEB costs may also be affected by changes in key
      assumptions, including anticipated rates of return on plan assets, the discount
      rates and health care trend rates used in determining the projected benefit
      obligations and pension and OPEB costs. FirstEnergy uses a December 31
      measurement date for most of its plans.


29


Unless
      otherwise
      indicated, the following tables provide information applicable to FirstEnergy's
      pension and OPEB plans.





**Obligations
                and Funded Status**
            
            **Pension
                Benefits**
            
            **Other
                Benefits****As
                of
                December 31****2005**
            
            **2004**
            
            **2005**
            
            **2004*****(In
                millions)*****Change
                in benefit obligation**Benefit
                obligation as of January 1
            
            $
            4,364
            
            $
            4,162
            
            $
            1,930
            
            $
            2,368Service
                cost
            
            
            77
            
            
            77
            
            
            40
            
            
            36Interest
                cost
            
            
            254
            
            
            252
            
            
            111
            
            
            112Plan
                participants’ contributions
            
            
            -
            
            
            -
            
            
            18
            
            
            14Plan
                amendments
            
            
            15
            
            
            -
            
            
            (312
            )
            
            (281
            )Actuarial
                (gain) loss
            
            
            310
            
            
            134
            
            
            197
            
            
            (211
            )Benefits
                paid
            
            
            (270
            )
            
            (261
            )
            
            (100
            )
            
            (108
            )Benefit
                obligation as of December 31
            
            $
            4,750
            
            $
            4,364
            
            $
            1,884
            
            $
            1,930**Change
                in fair value of plan assets**Fair
                value of
                plan assets as of January 1
            
            $
            3,969
            
            $
            3,315
            
            $
            564
            
            $
            537Actual
                return
                on plan assets
            
            
            325
            
            
            415
            
            
            33
            
            
            57Company
                contribution
            
            
            500
            
            
            500
            
            
            58
            
            
            64Plan
                participants’ contribution
            
            
            -
            
            
            -
            
            
            18
            
            
            14Benefits
                paid
            
            
            (270
            )
            
            (261
            )
            
            (100
            )
            
            (108
            )Fair
                value of
                plan assets as of December 31
            
            $
            4,524
            
            $
            3,969
            
            $
            573
            
            $
            564**Funded
                status**
            
            
            (226
            )
            $
            (395
            )
            
            (1,311
            )
            $
            (1,366
            )Unrecognized
                net actuarial loss
            
            
            1,179
            
            
            885
            
            
            899
            
            
            730Unrecognized
                prior service cost (benefit)
            
            
            70
            
            
            63
            
            
            (645
            )
            
            (378
            )Net
                asset
                (liability) recognized
            
            $
            1,023
            
            $
            553
            
            $
            (1,057
            )
            $
            (1,014
            )**Amounts
                Recognized in the****Consolidated
                Balance Sheets****As
                of
                December 31**
            
            
            
            
            
            
            
            
            -Prepaid
                benefit cost
            
            $
            1,023
            
            
            
            
            $
            -Accrued
                benefit cost
            
            
            -
            
            $
            (14
            )
            
            (1,057
            )
            $
            (1,014
            )Intangible
                assets
            
            
            -
            
            
            63
            
            
            -
            
            
            -Accumulated
                other comprehensive loss
            
            
            -
            
            
            504
            
            
            -
            
            
            -Net
                amount
                recognized
            
            $
            1,023
            
            $
            553
            
            $
            (1,057
            )
            $
            (1,014
            )Company's
                share of net amount recognized
            
            $
            139
            
            $
            47
            
            $
            (83
            )
            $
            (77
            )Decrease
                in
                minimum liability included in othercomprehensive
                income (net of tax)
            
            $
            (295
            )
            $
            (4
            )
            $
            -
            
            
            -**Assumptions
                Used to Determine****Benefit
                Obligations As of December 31**Discount
                rate
            
            
            5.75
            %
            
            6.00
            %
            
            5.75
            %
            
            6.00
            %Rate
                of
                compensation increase
            
            
            3.50
            %
            
            3.50
            %**Allocation
                of Plan Assets****As
                of
                December 31**Asset
                CategoryEquity
                securities
            
            
            63
            %
            
            68
            %
            
            71
            %
            
            74
            %Debt
                securities
            
            
            33
            
            
            29
            
            
            27
            
            
            25Real
                estate
            
            
            2
            
            
            2
            
            
            -
            
            
            -Cash
            
            
            2
            
            
            1
            
            
            2
            
            
            1Total
            
            
            100
            %
            
            100
            %
            
            100
            %
            
            100
            %





**Information
                for Pension Plans With an**
              **Accumulated
                Benefit Obligation in**
              **Excess
                of Plan Assets**
            
            **2005**
            
            **2004*****(In
                millions)***Projected
                benefit obligation
            
            $
            4,750
            
            $
            4,364Accumulated
                benefit obligation
            
            
            4,327
            
            
            3,983Fair
                value of
                plan assets
            
            
            4,524
            
            
            3,969







30





**Pension
                Benefits**
            
            **Other
                Benefits****Components
                of Net Periodic Benefit Costs**
            
            **2005**
            
            **2004**
            
            **2003**
            
            **2005**
            
            **2004**
            
            **2003*****(In
                millions)***Service
                cost
            
            $
            77
            
            $
            77
            
            $
            66
            
            $
            40
            
            $
            36
            
            $
            43Interest
                cost
            
            
            254
            
            
            252
            
            
            253
            
            
            111
            
            
            112
            
            
            137Expected
                return on plan assets
            
            
            (345
            )
            
            (286
            )
            
            (248
            )
            
            (45
            )
            
            (44
            )
            
            (43
            )Amortization
                of prior service cost
            
            
            8
            
            
            9
            
            
            9
            
            
            (45
            )
            
            (40
            )
            
            (9
            )Amortization
                of transition obligation
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            9Recognized
                net
                actuarial loss
            
            
            36
            
            
            39
            
            
            62
            
            
            40
            
            
            39
            
            
            40Net
                periodic
                cost
            
            $
            30
            
            $
            91
            
            $
            142
            
            $
            101
            
            $
            103
            
            $
            177Company's
                share of net periodic cost
            
            $
            1
            
            $
            6
            
            $
            10
            
            $
            15
            
            $
            18
            
            $
            15





**Weighted-Average
                Assumptions Used****to
                Determine Net Periodic Benefit Cost**
            
            **Pension
                Benefits**
            
            **Other
                Benefits****for
                Years Ended December 31**
            
            **2005**
            
            **2004**
            
            **2003**
            
            **2005**
            
            **2004**
            
            **2003**Discount
                rate
            
            
            6.00
            %
            
            6.25
            %
            
            6.75
            %
            
            6.00
            %
            
            6.25
            %
            
            6.75
            %Expected
                long-term return on plan assets
            
            
            9.00
            %
            
            9.00
            %
            
            9.00
            %
            
            9.00
            %
            
            9.00
            %
            
            9.00
            %Rate
                of
                compensation increase
            
            
            3.50
            %
            
            3.50
            %
            
            3.50
            %





In
      selecting an
      assumed discount rate, FirstEnergy considers currently available rates of return
      on high-quality fixed income investments expected to be available during the
      period to maturity of the pension and other postretirement benefit obligations.
      The assumed rates of return on pension plan assets consider historical market
      returns and economic forecasts for the types of investments held by the
      Company's pension trusts. The long-term rate of return is developed considering
      the portfolio’s asset allocation strategy.





FirstEnergy
      employs
      a total return investment approach whereby a mix of equities and fixed income
      investments are used to maximize the long-term return on plan assets for a
      prudent level of risk. Risk tolerance is established through careful
      consideration of plan liabilities, plan funded status, and corporate financial
      condition. The investment portfolio contains a diversified blend of equity
      and
      fixed-income investments. Furthermore, equity investments are diversified across
      U.S. and non-U.S. stocks, as well as growth, value, and small and large
      capitalization funds. Other assets such as real estate are used to enhance
      long-term returns while improving portfolio diversification. Derivatives may
      be
      used to gain market exposure in an efficient and timely manner; however,
      derivatives are not used to leverage the portfolio beyond the market value
      of
      the underlying investments. Investment risk is measured and monitored on a
      continuing basis through periodic investment portfolio reviews, annual liability
      measurements, and periodic asset/liability studies.





**Assumed
                Health Care Cost Trend Rates****As
                of
                December 31**
            
            **2005**
            
            **2004**Health
                care
                cost trend rate assumed for next year (pre/post-Medicare)
            
            9-11
            %
            9-11
            %Rate
                to which
                the cost trend rate is assumed to decline (the ultimate trend
                rate)
            
            
            5
            %
            
            5
            %Year
                that the
                rate reaches the ultimate trend rate (pre/post-Medicare)
            
            
            2010-2012
            
            
            2009-2011





Assumed
      health care
      cost trend rates have a significant effect on the amounts reported for the
      health care plans. A one-percentage-point change in assumed health care cost
      trend rates would have the following effects:





**1-Percentage-**
            
            **1-Percentage****Point
                Increase**
            
            **Point
                Decrease*****(In
                millions)***Effect
                on
                total of service and interest cost
            
            $
            23
            
            $
            (19
            )Effect
                on
                postretirement benefit obligation
            
            $
            239
            
            $
            (209
            )





As
      a result of its
      voluntary contribution and the increased market value of pension plan assets,
      the Company recognized a prepaid pension cost of $139 as of December 31,
      2005. As prescribed by SFAS 87, the Company eliminated its additional
      minimum liability of $51 million and its intangible asset of
      $14 million. In addition, the entire AOCL balance was credited by
      $22 million (net of $15 million of deferred taxes) as the fair value
      of trust assets exceeded the accumulated benefit obligation as of
      December 31, 2005.




31


Taking
      into account
      estimated employee future service, FirstEnergy expects to make the following
      benefit payments from plan assets:





**Pension
                Benefits**
            
            **Other
                Benefits*****(In
                millions)***2006
            
            $
            228
            
            $
            1062007
            
            
            228
            
            
            1092008
            
            
            236
            
            
            1122009
            
            
            247
            
            
            1152010
            
            
            264
            
            
            119Years
                2011-
                2015
            
            
            1,531
            
            
            642





**4.**  **FAIR
      VALUE
      OF FINANCIAL INSTRUMENTS:**





*Long-term
      Debt
      and Other Long-term Obligations-*





All
      borrowings with
      initial maturities of less than one year are defined as financial instruments
      under GAAP and are reported on the Consolidated Balance Sheets at cost, which
      approximates their fair market value. The following table provides the
      approximate fair value and related carrying amounts of long-term debt and other
      long-term obligations as of December 31:





**2005**
            
            **2004****Carrying**
            
            **Fair**
            
            **Carrying**
            
            **Fair****Value**
            
            **Value**
            
            **Value**
            
            **Value*****(In
                millions)***Long-term
                debt
            
            $
            1,901
            
            $
            2,016
            
            $
            1,915
            
            $
            2,079Subordinated
                debentures to affiliated trusts
            
            
            103
            
            
            140
            
            
            103
            
            
            112Preferred
                stock subject to mandatory redemption
            
            
            -
            
            
            -
            
            
            4
            
            
            4$
            2,004
            
            $
            2,156
            
            $
            2,022
            
            $
            2,195





The
      fair values of
      long-term debt and other long-term obligations reflect the present value of
      the
      cash outflows relating to those securities based on the current call price,
      the
      yield to maturity or the yield to call, as deemed appropriate at the end of
      each
      respective year. The yields assumed were based on securities with similar
      characteristics offered by a corporation with credit ratings similar to the
      Company's ratings.





*Investments-*





The
      carrying amounts
      of cash and cash equivalents approximate fair value due to the short-term nature
      of these investments. The following table provides the approximate fair value
      and related carrying amounts of investments other than cash and cash equivalents
      as of December 31:





**2005**
            
            **2004****Carrying**
            
            **Fair**
            
            **Carrying**
            
            **Fair****Value**
            
            **Value**
            
            **Value**
            
            **Value*****(In
                millions)***Debt
                securities:(1)-Government
                obligations
            
            $
            -
            
            $
            -
            
            $
            100
            
            $
            100-Corporate
                debt securities(2)
            
            
            1,625
            
            
            1,678
            
            
            734
            
            
            8541,625
            
            
            1,678
            
            
            834
            
            
            954Equity
                securities(1)
            
            
            -
            
            
            -
            
            
            242
            
            
            242$
            1,625
            
            $
            1,678
            
            $
            1,076
            
            $
            1,196





(1)  Includes
      nuclear
      decommissioning trust investments as of December 31, 2004.


(2)  Includes
      investments
      in lease obligation bonds (see Note 5).





The
      fair value of
      investments other than cash and cash equivalents represent cost (which
      approximates fair value) or the present value of the cash inflows based on
      the
      yield to maturity. The yields assumed were based on financial instruments with
      similar characteristics and terms.





Investments
      other
      than cash and cash equivalents include held-to-maturity securities and
      available-for-sale securities. Prior to their transfer to NGC (see Note 11),
      the
      Company's decommissioning trust investments were classified as
      available-for-sale. The Company has no securities held for trading
      purposes.




32


Proceeds
      from the
      sale of decommissioning trust investments, gross realized gains and losses
      on
      those sales, and interest and dividend income for the three years ended
      December 31, 2005 were as follows:





**2005**
            
            **2004**
            
            **2003*****(In
                millions)***Proceeds
                from
                sales
            
            $
            475
            
            $
            411
            
            $
            226Gross
                realized
                gains
            
            
            49
            
            
            35
            
            
            15Gross
                realized
                losses
            
            
            20
            
            
            21
            
            
            16Interest
                and
                dividend income
            
            
            12
            
            
            11
            
            
            9





Prior
      to their
      transfer to NGC, unrealized gains and losses applicable to the Company's
      decommissioning trusts were recognized in OCI in accordance with SFAS 115.





The
      investment
      policy for the nuclear decommissioning trust funds restricts or limits the
      ability to hold certain types of assets including private or direct placements,
      warrants, securities of FirstEnergy, investments in companies owning nuclear
      power plants, financial derivatives, preferred stocks, securities convertible
      into common stock and securities of the trust fund's custodian or managers
      and
      their parents or subsidiaries.





**5.**  **LEASES:**





The
      Company leases
      certain generating facilities, office space and other property and equipment
      under cancelable and noncancelable leases.





The
      Company and TE
      sold their ownership int erests
      in Bruce
      Mansfield Units 1, 2 and 3 and TE sold a portion of its ownership interest
      in Beaver Valley Unit 2. In connection with these sales, which were
      completed in 1987, the Company and TE entered into operating leases for lease
      terms of approximately 30 years as co-lessees. During the terms of the leases,
      the Company and TE continue to be responsible, to the extent of their leasehold
      interest, for costs associated with the units including construction
      expenditures, operation and maintenance expenses, insurance, nuclear fuel,
      property taxes and decommissioning. The Company and TE have the right, at the
      end of the respective basic lease terms, to renew the leases. The Company and
      TE
      also have the right to purchase the facilities at the expiration of the basic
      lease term or any renewal term at a price equal to the fair market value of
      the
      facilities.





As
      co-lessee with
      TE, the Company is also obligated for TE's lease payments. If TE is unable
      to
      make its payments under the Beaver Valley Unit 2 and Bruce Mansfield Plant
      leases, the Company would be obligated to make such payments. No such payments
      have been made on behalf of TE. (TE's future minimum lease payments as of
      December 31, 2005 were approximately $0.8 billion, net of trust cash
      receipts.)





Consistent
      with the
      regulatory treatment, the rentals for capital and operating leases are charged
      to operating expenses on the Consolidated Statements of Income. Such costs
      for
      the three years ended December 31, 2005 are summarized as
      follows:





**2005**
            
            **2004**
            
            **2003*****(In
                millions)***Operating
                leasesInterest
                element
            
            $
            28.4
            
            $
            29.1
            
            $
            31.9Other
            
            
            40.9
            
            
            29.4
            
            
            48.0Capital
                leasesInterest
                element
            
            
            0.5
            
            
            0.5
            
            
            0.6Other
            
            
            0.5
            
            
            0.5
            
            
            0.4Total
                rentals
            
            $
            70.3
            
            $
            59.5
            
            $
            80.9





The
      future minimum
      lease payments as of December 31, 2005 are:





**Operating
                Leases****Capital**
            
            **Lease**
            
            **Capital****Leases**
            
            **Payments**
            
            **Trust**
            
            **Net*****(In
                millions)***2006
            
            $
            1.0
            
            $
            75.2
            
            $
            56.2
            
            $
            19.02007
            
            
            1.0
            
            
            61.7
            
            
            48.2
            
            
            13.52008
            
            
            1.0
            
            
            57.8
            
            
            42.9
            
            
            14.92009
            
            
            1.0
            
            
            59.6
            
            
            46.1
            
            
            13.52010
            
            
            1.0
            
            
            59.9
            
            
            49.0
            
            
            10.9Years
                thereafter
            
            
            1.6
            
            
            377.9
            
            
            255.2
            
            
            122.7Total
                minimum
                lease payments
            
            
            6.6
            
            $
            692.1
            
            $
            497.6
            
            $
            194.5Interest
                portion
            
            
            (1.7
            )Present
                value
                of net minimum
              lease
                payments
            
            
            4.9Less
                current
                portion
            
            
            (0.5
            )Noncurrent
                portion
            
            $
            4.4





33


The
      Company has
      recorded above-market lease liabilities for Beaver Valley Unit 2 and the
      Bruce Mansfield Plant associated with the 1997 merger creating FirstEnergy.
      The
      total above-market lease obligation of $611 million associated with Beaver
      Valley Unit 2 is being amortized on a straight-line basis through the end
      of the lease term in 2017 (approximately $31 million per year). The total
      above-market lease obligation of $457 million associated with the Bruce
      Mansfield Plant is being amortized on a straight-line basis through the end
      of
      2016 (approximately $29 million per year). As of December 31, 2005 the
      above-market lease liabilities for Beaver Valley Unit 2 and the Bruce
      Mansfield Plant totaled approximately $668 million, of which
      $60 million is payable within one year.





The
      Company and TE
      refinanced high-cost fixed obligations related to their 1987 sale and leaseback
      transaction for the Bruce Mansfield Plant through a lower cost transaction
      in
      June and July 1997. In a June 1997 offering, the two companies pledged
      $720 million aggregate principal amount ($575 million for the Company
      and $145 million for TE) of FMB due through 2007 to a trust as security for
      the issuance of a like principal amount of secured notes due through 2007.
      The
      obligations of the two companies under these secured notes are joint and
      several. Using available cash, short-term borrowings and the net proceeds from
      the offering, the two companies invested $907 million ($569 million
      for the Company and $337 million for TE) in a business trust, in June 1997.
      The trust used these funds in July 1997 to purchase lease notes and redeem
      all
      $873 million aggregate principal amount of 10-1/4% and 11-1/8% secured
      lease obligation bonds (SLOBs) due 2003 and 2016. The SLOBs were issued by
      a
      special-purpose-funding corporation in 1988 on behalf of lessors in the two
      companies' 1987 sale and leaseback transactions. The Shippingport arrangement
      effectively reduces lease costs related to that transaction.





**6.**  **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 adopted
      FIN 46R for special-purpose entities as of December 31, 2003 and for all
      other entities in the first quarter of 2004. The Company consolidates VIEs
      when
      it is determined to be the VIE's primary beneficiary as defined by FIN 46R.





Included
      in the
      Company's consolidated financial statements is Shippingport, a VIE created
      in
      1997, to refinance debt originally issued in connection with the Bruce Mansfield
      Plant sale and leaseback transaction.





Shippingport
      was
      established to purchase all of the SLOBs issued in connection with the Company's
      and TE's Bruce Mansfield Plant sale and leaseback transaction in 1987. The
      Company and TE used debt and available funds to purchase the notes issued by
      Shippingport. Shippingport's note payable to TE of $189 million
      ($12 million current) and $199 million ($10 million current) as
      of December 31, 2005 and December 31, 2004, respectively, is included
      in long-term debt on the Company's Consolidated Balance Sheets.





Through
      its
      investment in Shippingport, the Company has a variable interest in certain
      owner
      trusts that acquired the interests in the Bruce Mansfield Plant. The Company
      has
      concluded that it was not the primary beneficiary of the owner trusts and was
      therefore not required to consolidate these entities. The leases are accounted
      for as operating leases in accordance with GAAP.





The
      Company is
      exposed to losses under the sale-leaseback agreements upon the occurrence of
      certain contingent events that it considers unlikely to occur. The Company
      has 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 sale and leaseback agreement, the Company has net minimum
      discounted lease payments of $105 million, that would not be payable if the
      casualty value payments are made.





**7.**  **SALE
      OF
      GENERATING ASSETS:**





In
      August 2002,
      FirstEnergy cancelled a November 2001 agreement to sell four coal-fired power
      plants (2,535 MW) to NRG Energy Inc. because NRG stated that it could not
      complete the transaction under the original terms of the agreement. NRG filed
      voluntary bankruptcy petitions in May 2003; subsequently, FirstEnergy reached
      an
      agreement for settlement of its claim against NRG. FirstEnergy sold its entire
      claim (including $32 million of cash proceeds received in December 2003)
      for $170 million (Company's share - $131 million).




34


**8.**  **OHIO
      TAX
      LEGISLATION**





On
      June 30,
      2005, tax legislation was
      enacted in the
      State of Ohio that created a new CAT tax, which is based on qualifying “taxable
      gross receipts” and does not consider any expenses or costs incurred to generate
      such receipts, except for items such as cash discounts, returns and allowances,
      and bad debts. The CAT tax was effective July 1, 2005, and replaces the
      Ohio income-based franchise tax and the Ohio personal property tax. The CAT
      tax
      is phased-in while the current income-based franchise tax is phased-out over
      a
      five-year period at a rate of 20% annually, beginning with the year ended 2005,
      and the personal property tax is phased-out over a four-year period at a rate
      of
      approximately 25% annually, beginning with the year ended 2005. During the
      phase-out period the Ohio income-based franchise tax will be computed consistent
      with the prior tax law, except that the tax liability as computed will be
      multiplied by 4/5 in 2005; 3/5 in 2006; 2/5 in 2007 and 1/5 in 2008, therefore
      eliminating the current income-based franchise tax over a five-year period.
      As a
      result of the new tax structure, all net deferred tax benefits that were not
      expected to reverse during the five-year phase-in period were written-off as
      of
      June 30, 2005. The
      impact on income
      taxes associated with the required adjustment to net deferred taxes for 2005
      was
      an additional tax expense of approximately $4 million, which was partially
      offset by the initial phase-out of the Ohio income-based franchise tax, which
      reduced income taxes by approximately $5 million in 2005.





**9.**  **REGULATORY
      MATTERS:**





Regulatory
      assets
      are costs which have been authorized by the PUCO and the FERC for recovery
      from
      customers in the future periods or for which authorization is probable. Without
      the probability of such authorization, costs currently recorded as regulatory
      assets would have been charged to income as incurred. All regulatory assets
      are
      expected to be recovered under the provisions of our transition plan and rate
      restructuring plan.





In
      late 2003 and
      early 2004, a series of letters, reports and recommendations were issued from
      various entities, including governmental, industry and ad-hoc reliability
      entities (PUCO, FERC, NERC and the U.S. - Canada Power System Outage Task Force)
      regarding enhancements to regional reliability. In 2004, FirstEnergy completed
      implementation of all actions and initiatives related to enhancing area
      reliability, improving voltage and reactive management, operator readiness
      and
      training and emergency response preparedness recommended for completion in
      2004.
      On July 14, 2004, NERC independently verified that FirstEnergy had
      implemented the various initiatives to be completed by June 30 or summer
      2004, with minor exceptions noted by FirstEnergy, which exceptions are now
      essentially complete. FirstEnergy is proceeding with the implementation of
      the
      recommendations that were to be completed subsequent to 2004 and will continue
      to periodically assess the FERC-ordered Reliability Study recommendations for
      forecasted 2009 system conditions, recognizing revised load forecasts and other
      changing system conditions which may impact the recommendations. Thus far,
      implementation of the recommendations has not required, nor is expected to
      require, substantial investment in new, or material upgrades to existing
      equipment. The FERC or other applicable government agencies and reliability
      coordinators may, however, take a different view as to recommended enhancements
      or may recommend additional enhancements in the future as the result of adoption
      of mandatory reliability standards pursuant to the EPACT that could require
      additional, material expenditures. Finally, the PUCO is continuing to review
      the
      FirstEnergy filing that addressed upgrades to control room computer hardware
      and
      software and enhancements to the training of control room operators before
      determining the next steps, if any, in the proceeding.





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
      NERC has been
      preparing the implementation aspects of reorganizing its structure to meet
      the
      FERC’s certification requirements for the ERO. The NERC will make a filing with
      the FERC to obtain certification as the ERO and to obtain FERC approval of
      delegation agreements with regional entities. The new FERC rule referred to
      above, further provides for reorganizing regional reliability organizations
      (regional entities) that would replace the current regional councils and for
      rearranging the relationship with the ERO. The “regional entity” may be
      delegated authority by the ERO, subject to FERC approval, for enforcing
      reliability standards adopted by the ERO and approved by the FERC. NERC also
      intends to make a parallel filing with the FERC seeking approval of mandatory
      reliability standards. These
      reliability
      standards are expected to be based on the current NERC Version 0 reliability
      standards with some additional standards. The
      two filings are
      expected to be made in the second quarter of 2006.





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.




35


On
      a parallel path,
      the NERC is establishing working groups to develop reliability standards to
      be
      filed for approval with the FERC following the NERC’s certification as an ERO.
      These reliability standards are expected to build on the current NERC Version
      0
      reliability standards. It is expected that the proposed reliability standards
      will be filed with the FERC in early 2006.





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 Version 0 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.





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





On
      December 29,
      2005, the FERC issued an order setting the two power sales agreements for
      hearing. The order criticizes the Ohio competitive bid process, and requires
      FES
      to submit additional evidence in support of the reasonableness of the prices
      charged in the Ohio and Pennsylvania Contracts. A pre-hearing conference was
      held on January 18, 2006 to determine the hearing schedule in this case.
      FES expects an initial decision to be issued in this case in the fall of 2006.
      The outcome of this proceeding cannot be predicted. FES has sought rehearing
      of
      the December 29, 2005 order.





On
      August 5,
      2004, the Company accepted the RSP as modified and approved by the PUCO in
      an
      August 4, 2004 Entry on Rehearing, subject to a competitive bid process.
      The RSP was intended to establish generation service rates beginning
      January 1, 2006, in response to PUCO concerns about price and supply
      uncertainty following the end of the Company's transition plan market
      development period. In October 2004, the OCC and NOAC filed appeals with the
      Supreme Court of Ohio to overturn the original June 9, 2004 PUCO order in
      this proceeding as well as the associated entries on rehearing. On
      September 28, 2005, the Ohio Supreme Court heard oral arguments on the
      appeals and it is expected that the Court will issue its opinion in 2006. On
      November 1, 2005, the Company filed tariffs in compliance with the approved
      RSP, which were approved by the PUCO on December 7, 2005.





On
      May 27,
      2005, the Company filed an application with the PUCO to establish a GCAF rider
      under the RSP. The GCAF application sought recovery of increased fuel costs
      from
      2006 through 2008 applicable to the Company's retail customers through a tariff
      rider to be implemented January 1, 2006. The application reflected
      projected increases in fuel costs in 2006 compared to 2002 baseline costs.
      The
      new rider, after adjustments made in testimony, sought to recover all costs
      above the baseline (approximately $88 million in 2006 for all the Ohio
      Companies). Various parties including the OCC intervened in this case and the
      case was consolidated with the RCP application discussed below.





On
      September 9,
      2005, the Company filed an application with the PUCO that supplemented its
      existing RSP with an RCP which was designed to provide customers with more
      certain rate levels than otherwise available under the RSP during the plan
      period. Major provisions of the RCP include:




·
              Maintain
                  the
                  existing level of base distribution rates through April 30, 2009
                  for
                  CEI;
 
 ·
              Defer
                  and
                  capitalize for future recovery 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;
 
 ·
              Adjust
                  the RTC
                  and extended RTC recovery periods and rate levels so that full
                  recovery of
                  authorized costs will occur as of December 31, 2010 for
                  CEI;
 
 ·
              Reduce
                  the
                  deferred shopping incentive balances as of January 1, 2006 by up to
                  $85 million for CEI by accelerating the application of its accumulated
                  cost of removal regulatory liability;
                  and
 
 ·
              Defer
                  and
                  capitalize all of CEI's allowable fuel cost increases until January
                  1, 2009.






36




On
      November 4,
      2005, a supplemental stipulation was filed with the PUCO which was in addition
      to a stipulation filed with the September 9, 2005 application. On
      January 4, 2006, the PUCO approved the RCP filing with modifications. On
      January 10, 2006, the Company filed a Motion for Clarification of the PUCO
      order approving the RCP. The Company 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 Company 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 Company's previous requests and clarifying issues referred to above.
      The PUCO granted the Ohio Company's requests to: 1) recognize fuel and
      distribution deferrals commencing January 1, 2006; 2) recognize distribution
      deferrals on a monthly basis prior to review by the PUCO Staff; 3) clarify
      that
      the types of distribution expenditures included in the Supplemental Stipulation
      may be deferred; and 4) clarify that distribution expenditures do not have
      to be
“accelerated” in order to be deferred. The PUCO granted the Company's
      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 Company's Motion. On February 3, 2006, several other parties filed
      applications for rehearing on the PUCO's January 4, 2006 Order. The Company
      responded to the application for rehearing on February 13, 2006.





Under
      provisions of
      the RSP, the PUCO may require the Company to undertake, no more often than
      annually, a competitive bid process to secure generation for the years 2007
      and
      2008. On July 22, 2005, FirstEnergy filed a competitive bid process for the
      period beginning in 2007 that is similar to the competitive bid process approved
      by the PUCO for the Company in 2004, which resulted in the PUCO accepting no
      bids. Any acceptance of future competitive bid results would terminate the
      RSP
      pricing, with no accounting impacts to the RSP, and not until twelve months
      after the PUCO authorizes such termination. On September 28, 2005, the PUCO
      issued an Entry that essentially approved the Company's filing but delayed
      the
      proposed timing of the competitive bid process by four months, calling for
      the
      auction to be held on March 21, 2006. OCC filed an application for
      rehearing of the September 28, 2005 Entry, which the PUCO denied on
      November 22, 2005. On February 23, 2006, the auction manager notified the
      PUCO that there was insufficient interest in the auction process to allow it
      to
      proceed in 2006.





On
      December 30,
      2004, the Company 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 Company
      requested that these costs be recovered through a rider that would be effective
      on January 1, 2006 and adjusted each July 1 thereafter. The PUCO
      approved the settlement stipulation on August 31, 2005. The incremental
      transmission and ancillary service revenues expected to be recovered from
      January through June 2006 are approximately $24 million. This amount
      includes the recovery of the 2005 deferred MISO expenses as described below.
      In
      May 2006, the Company will file a modification to the rider to determine
      revenues from July 2006 through June 2007.





The
      second
      application sought authority to defer costs associated with transmission and
      ancillary service related costs incurred during the period from October 1,
      2003 through December 31, 2005. On May 18, 2005, the PUCO granted the
      accounting authority for the Company 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 Company to
      accrue carrying charges on the deferred balances. On August 31, 2005, the
      OCC appealed the PUCO's decision. All briefs have been filed. A motion to
      dismiss filed on behalf of the PUCO is currently pending. Unless the court
      grants the motion, the appeal will be set for oral argument, which should be
      heard in the third or fourth quarter of 2006.





On
      January 20,
      2006 the OCC sought rehearing of the PUCO approval of the rider recovery during
      the period January 1, 2006 through June 30, 2006, as that amount pertains
      to recovery of the deferred costs. The PUCO denied the OCC's application on
      February 6, 2006. The OCC has sixty days from that date to appeal the
      PUCO's approval of the rider.





**10.**  **CAPITALIZATION:**





**(** **A)**  **RETAINED
      EARNINGS-**





There
      are no
      restrictions on retained earnings for payment of cash dividends on the Company’s
      common stock.





**(B)**  **PREFERRED
      AND PREFERENCE STOCK-**





No
      preferred stock
      shares are currently outstanding.





The
      preferred
      dividend rate on the Company’s Series L fluctuated based on prevailing
      interest rates and market conditions. The dividend rate for this issue was
      7% in
      2005.





The
      Company has
      three million authorized and unissued shares of preference stock having no
      par value.




37


**(C)**  **LONG-TERM
      DEBT AND OTHER LONG-TERM OBLIGATIONS-**





The
      Company has a
      first mortgage indenture under which it issues FMB secured by a direct first
      mortgage lien on substantially all of its property and franchises, other than
      specifically excepted property. The Company has various debt covenants under
      its
      financing arrangements. The most restrictive of the debt covenants relate to
      the
      nonpayment of interest and/or principal on debt which could trigger a default
      and the maintenance of minimum fixed charge ratios and debt to capitalization
      ratios covenants. There also exist cross-default provisions among financing
      agreements of FirstEnergy and the Company.





Sinking
      fund
      requirements for FMB and maturing long-term debt (excluding capital leases)
      for
      the next five years are:




***(In
                millions)***2006
            $
            752007
            
            1292008
            
            2212009
            
            1622010
            
            18





Included
      in the
      table above are amounts for various variable interest rate long-term debts
      that
      have provisions by which individual debt holders are required to "put back"
      the
      respective debt to the issuer for redemption prior to its maturity date. These
      amounts are $75 million and $82 million in 2006 and 2008,
      respectively, representing the next times debt holders may exercise this
      provision.





The
      Company's
      obligations to repay certain pollution control revenue bonds are secured by
      several series of FMB. Certain pollution control revenue bonds are entitled
      to
      the benefit of irrevocable bank LOCs of $76 million and noncancelable
      municipal bond insurance policies of $361 million to pay principal of, or
      interest on, the pollution control revenue bonds. To the extent that drawings
      are made under the LOCs or policies, the Company is entitled to a credit against
      its obligation to repay that bond. The Company pays annual fees of 0.875% to
      1.625% of the amounts of the LOCs to the issuing bank and 0.213% to 0.600%
      of
      the amounts of the policies to the insurers and are obligated to reimburse
      the
      bank or insurers, as the case maybe, for any drawings thereunder.





Certain
      secured
      notes of the Company are entitled to the benefit of noncancelable municipal
      bond
      insurance policies of $120 million to pay principal of, or interest on, the
      applicable notes. To the extent that drawings are made under the policy, the
      Company is entitled to a credit against its obligation to repay those notes.
      The
      Company is obligated to reimburse the insurer for any drawings
      thereunder.





The
      Company and TE
      have unsecured LOCs of approximately $194 million in connection with the
      sale and leaseback of Beaver Valley Unit 2. The Company and TE are jointly
      and severally liable for the LOCs (see Note 5).





**(D)**  **SUBORDINATED
      DEBENTURES TO AFFILIATED TRUSTS-**





As
      of
      December 31, 2005, the Company's wholly owned statutory business trust,
      Cleveland Electric Financing Trust, had $100 million of outstanding 9.00%
      preferred securities maturing in 2031. The sole assets of the trust are the
      Company's subordinated debentures with the same rate and maturity date as the
      preferred securities.





The
      Company formed
      the trust to sell preferred securities and invest the gross proceeds in the
      9.00% subordinated debentures of the Company. The sole assets of the trust
      are
      the applicable subordinated debentures. Interest payment provisions of the
      subordinated debentures match the distribution payment provisions of the trust's
      preferred securities. In addition, upon redemption or payment at maturity of
      subordinated debentures, the trust's preferred securities will be redeemed
      on a
      pro rata basis at their liquidation value. Under certain circumstances, the
      applicable subordinated debentures could be distributed to the holders of the
      outstanding preferred securities of the trust in the event that the trust is
      liquidated. The Company has effectively provided a full and unconditional
      guarantee of payments due on the trust's preferred securities. The trust's
      preferred securities are redeemable at 100% of their principal amount at the
      Company's option beginning in December 2006. Interest on the subordinated
      debentures (and therefore distributions on the trust's preferred securities)
      may
      be deferred for up to 60 months, but the Company may not pay dividends on,
      or redeem or acquire, any of its cumulative preferred or common stock until
      deferred payments on its subordinated debentures are paid in full.





**11.**  **ASSET
      RETIREMENT OBLIGATION:**





In
      January 2003, the
      Company implemented SFAS 143, which provides accounting guidance for
      retirement obligations associated with tangible long-lived assets. This standard
      requires recognition of the fair value of a liability for an ARO in the period
      in which it is incurred. The associated asset retirement costs are capitalized
      as part of the carrying amount of the long-lived asset. Over time the
      capitalized costs are depreciated and the present value of the ARO increases,
      resulting in a period expense. Upon retirement, a gain or loss would be
      recognized if the cost to settle the retirement obligation differs from the
      carrying amount.




38




The
        Company
        initially identified applicable legal obligations as defined under the standard
        for nuclear power plant decommissioning of Beaver Valley Unit 2,
        Davis-Besse and Perry nuclear generating facilities, reclamation of a
        sludge disposal
        pond related to the Bruce Mansfield Plant and closure of two coal ash disposal
        sites. The ARO liability as of the date of adoption was $238 million,
        including accumulated accretion for the period from the date the liability
        was
        incurred to the date of adoption. The Company’s share of the obligation to
        decommission these units was developed based on site specific studies performed
        by an independent engineer. The Company utilized an expected cash flow approach
        to measure the fair value of the nuclear decommissioning ARO.
 
 Pursuant
        to the
        generation asset transfers on October 24, 2005 and December 16, 2005,
        FGCO and NGC now own nearly all of the fossil and nuclear generation assets,
        respectively, previously owned by the Company. The generating plant interests
        transferred do not include leasehold interests of the Company that are currently
        subject to sale and leaseback arrangements with non-affiliates (see
        Note 14). As a result, only the ARO associated with the two coal ash
        disposal sites and the sale and leaseback arrangements remain with the
        Company.
 
 The
        Company
        implemented FIN 47, "Accounting for Conditional Asset Retirement
        Obligations", an interpretation of SFAS 143 on December 31, 2005.
        FIN 47 provides accounting standards for conditional retirement obligations
        associated with tangible long-lived assets, requiring recognition of the
        fair
        value of a liability for an ARO in the period in which it is incurred if
        a
        reasonable estimate can be identified. FIN 47 states that an **** obligation
        exists
        even though there may be uncertainty about timing or method of settlement
        and **** further
        clarifies
        SFAS 143, stating that the uncertainty surrounding the timing and method of
        settlement when settlement is conditional on a future event occurring should
        be
        reflected in the measurement of the liability not in the recognition of the
        liability. The recognition requirement of the conditional ARO under FIN 47
        is the same as SFAS 143, in that the associated asset retirement costs are
        capitalized as part of the carrying amount of the long-lived asset. Over
        time
        the capitalized costs are depreciated and the present value of the asset
        retirement liability increases, resulting in a period expense. However,
        rate-regulated entities may recognize a regulatory asset or liability instead
        if
        the criteria for such treatment are met. Upon retirement, a gain or loss
        would
        be recognized if the cost to settle the retirement obligation differs from
        the
        carrying amount.
 
 The
        Company
        identified applicable legal obligations as defined under the new standard
        at its
        retired generating
        units,
        substation control rooms, service center buildings, line shops and office
        buildings, identifying asbestos as the primary conditional ARO. As
        a result of
        adopting FIN 47 in December 2005, the Company recorded a
        conditional ARO
        liability of $7 million (including accumulated accretion for the period
        from the date the liability was incurred to the date of adoption), an asset
        retirement cost of $2 million (recorded as part of the carrying amount of
        the related long-lived asset), and accumulated depreciation of $2 million. T he
        Company
        recognized a regulatory liability of $1 million upon adoption of
        FIN 47 for the transition amounts related to establishing the ARO for
        asbestos removal from substation control room and service center buildings,
        therefore requiring a $6 million cumulative effect adjustment
        ($4 million, net of tax) for unrecognized depreciation and accretion to be
        recorded as of December 31, 2005. The
        obligation to
        remediate asbestos, lead paint abatement and other remediation costs at the
        retired generating units was developed based on site specific studies performed
        by an independent engineer. The costs of remediation at the substation control
        rooms, service center buildings, line shops and office buildings were based
        on
        costs incurred during recent remediation projects performed at each of these
        locations, respectively. The conditional ARO liability was the developed
        utilizing an expected cash flow approach (as discussed in SFAC 7) to
        measure the fair value of the ARO. The Company used a probability weighted
        analysis to estimate when remediation payments would begin. The effect on
        income
        as if FIN 47 had been applied during 2004 and 2003 is
        immaterial.




The
      following table
      describes the changes to the ARO balances during 2005 and 2004.





**2005**
            
            **2004****ARO
                Reconciliation**
            
            ***(In
                millions)***Balance
                at
                beginning of year
            
            $
            272
            
            $
            255Transfers
                to
                FGCO and NCG
            
            
            (247)
            
            
            -Accretion
            
            
            17
            
            
            17Revisions
                in
                estimated cash flows
            
            
            (41)
            
            
            -FIN
                47
                ARO
            
            
            7
            
            
            -Balance
                at end
                of year
            
            $
            8
            
            $
            272





**12.**  **SHORT-TERM
      BORROWINGS:**





Short-term
      borrowings outstanding as of December 31, 2005, consisted of $ 212 million
      of
      borrowings from affiliates and $140 million of CFC borrowings. CFC is a
      wholly owned subsidiary of the Company whose borrowings are secured by customer
      accounts receivable purchased from the Company and TE. CFC can borrow up to
      $200 million under a receivables financing arrangement at rates based on
      certain bank commercial paper and is required to pay an annual fee of 0.25%
      on
      the amount of the entire finance limit. The receivables financing agreement
      expires in December 2006. 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 the Company.




39


In
      June 2005,
      the Company, FirstEnergy, OE, Penn, TE, JCP&L, Met-Ed, Penelec, FES and
      ATSI, as Borrowers, 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. The Company's borrowing limit
      under the facility is $250 million. The average interest rate on short-term
      borrowings outstanding as of December 31, 2005 and 2004 was 4.2% and 2.1%,
      respectively.





**13.**  **COMMITMENTS
      AND CONTINGENCIES:**




**(****A)**
              **ENVIRONMENTAL
                  MATTERS-**





The
      Company accrues
      environmental liabilities only when they conclude that it is probable that
      they
      have an obligation for such costs and can reasonably estimate the amount of
      such
      costs. Unasserted claims are reflected in the Company’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.





*Regulation
      of
      Hazardous Waste*





The
      Company has been
      named as a PRP at waste disposal sites, which may require cleanup under the
      Comprehensive Environmental Response, Compensation, and Liability Act of 1980.
      Allegations of disposal of hazardous substances at historical sites and the
      liability involved are often unsubstantiated and subject to dispute; however,
      federal law provides that all PRPs for a particular site are liable on a joint
      and several basis. Therefore, environmental liabilities that are considered
      probable have been recognized on the Consolidated Balance Sheet as of
      December 31, 2005, based on estimates of the total costs of cleanup, the
      Company’s proportionate responsibility for such costs and the financial ability
      of other unaffiliated entities to pay. Total liabilities of approximately
      $1.7 million have been accrued through December 31, 2005.





**(B)**
            **OTHER
                LEGAL PROCEEDINGS-**




*Power
      Outages
      and Related Litigation*





On
      August 14,
      2003, various states and parts of southern Canada experienced widespread power
      outages. The outages affected approximately 1.4 million customers in
      FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s
      final report in April 2004 on the outages concluded, among other things, that
      the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically,
      the
      final report concluded, among other things, that the initiation of the
      August 14, 2003 power outages resulted from an alleged failure of both
      FirstEnergy and ECAR to assess and understand perceived inadequacies within
      the
      FirstEnergy system; inadequate situational awareness of the developing
      conditions; and a perceived failure to adequately manage tree growth in certain
      transmission rights of way. The Task Force also concluded that there was a
      failure of the interconnected grid's reliability organizations (MISO and PJM)
      to
      provide effective real-time diagnostic support. The final report is publicly
      available through the Department of Energy’s website (www.doe.gov). FirstEnergy
      believes that the final report does not provide a complete and comprehensive
      picture of the conditions that contributed to the August 14, 2003 power
      outages and that it does not adequately address the underlying causes of the
      outages. FirstEnergy remains convinced that the outages cannot be explained
      by
      events on any one utility's system. The final report contained 46
“recommendations to prevent or minimize the scope of future blackouts.”
Forty-five of those recommendations related to broad industry or policy matters
      while one, including subparts, related to activities the Task Force recommended
      be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct
      the
      causes of the August 14, 2003 power outages. FirstEnergy implemented
      several initiatives, both prior to and since the August 14, 2003 power
      outages, which were independently verified by NERC as complete in 2004 and
      were
      consistent with these and other recommendations and collectively enhance the
      reliability of its electric system. FirstEnergy’s implementation of these
      recommendations in 2004 included completion of the Task Force recommendations
      that were directed toward FirstEnergy. FirstEnergy also is proceeding with
      the
      implementation of the recommendations regarding enhancements to regional
      reliability that were to be completed subsequent to 2004 and will continue
      to
      periodically assess the FERC-ordered Reliability Study recommendations for
      forecasted 2009 system conditions, recognizing revised load forecasts and other
      changing system conditions which may impact the recommendations. Thus far
      implementation of the recommendations has not required, nor is expected to
      require, substantial investment in new or material upgrades to existing
      equipment, and therefore FirstEnergy has not accrued a liability as of
      December 31, 2005 for any expenditures in excess of those actually incurred
      through that date. The FERC or other applicable government agencies and
      reliability coordinators may, however, take a different view as to recommended
      enhancements or may recommend additional enhancements in the future that could
      require additional, material expenditures. Finally, the PUCO is continuing
      to
      review FirstEnergy’s filing that addressed upgrades to control room computer
      hardware and software and enhancements to the training of control room operators
      before determining the next steps, if any, in the proceeding.




40


FirstEnergy
      companies are also defending six separate complaint cases before the PUCO
      relating to the August 14, 2003 power outage. Two cases were originally
      filed in Ohio State courts but were subsequently dismissed for lack of subject
      matter jurisdiction and further appeals were unsuccessful. In these cases the
      individual complainants—three in one case and four in the other—sought to
      represent others as part of a class action. The PUCO dismissed the class
      allegations, stating that its rules of practice do not provide for class action
      complaints. Of the four other pending PUCO complaint cases, three were filed
      by
      various insurance carriers either in their own name as subrogees or in the
      name
      of their insured. In each of the four cases, the carriers seek reimbursement
      against various FirstEnergy companies (and, in one case, from PJM, MISO and
      American Electric Power Company as well) for claims paid to insureds for claims
      allegedly arising as a result of the loss of power on August 14, 2003. The
      listed insureds in these cases, in many instances, are not customers of any
      FirstEnergy company. The fourth case involves the claim of a non-customer
      seeking reimbursement for losses incurred when its store was burglarized on
      August 14, 2003. In addition to these six cases, the Ohio Companies were
      named as respondents in a regulatory proceeding that was initiated at the PUCO
      in response to complaints alleging failure to provide reasonable and adequate
      service stemming primarily from the August 14, 2003 power outages. No
      estimate of potential liability has been undertaken for any of these cases.





In
      addition to the
      above proceedings, FirstEnergy was named in a complaint filed in Michigan State
      Court by an individual who is not a customer of any FirstEnergy company. A
      responsive pleading to this matter has been filed. FirstEnergy was also named,
      along with several other entities, in a complaint in New Jersey State Court.
      The
      allegations against FirstEnergy are based, in part, on an alleged failure to
      protect the citizens of Jersey City from an electrical power outage. No
      FirstEnergy entity serves any customers in Jersey City. A responsive pleading
      has been filed. No estimate of potential liability has been undertaken in either
      of these matters.





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





*Nuclear
      Plant
      Matters*





As
      of
      December 16, 2005 NGC acquired ownership of the nuclear generation assets
      transferred from the Company, OE, 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. The transfer included the
      Company's prior interests in Beaver Valley Unit 2 (24.47%), Davis-Besse (51.38%)
      and Perry (44.85%).





On
      May 11,
      2005, FENOC received a subpoena for documents related to outside meetings
      attended by Davis-Besse personnel on corrosion and cracking of control rod
      drive
      mechanisms and additional root cause evaluations. On January 20, 2006,
      FENOC announced that it has entered into a deferred prosecution agreement with
      the U.S. Attorney’s Office for the Northern District of Ohio and the
      Environmental Crimes Section of the Environment and Natural Resources Division
      of the DOJ related to FENOC’s communications with the NRC during the fall of
      2001 in connection with the reactor head issue at the Davis-Besse Nuclear Power
      Station. Under the agreement, which expires on December 31, 2006, the United
      States acknowledged FENOC’s extensive corrective actions at Davis-Besse, FENOC’s
      cooperation during investigations by the DOJ and the NRC, FENOC’s pledge of
      continued cooperation in any related criminal and administrative investigations
      and proceedings, FENOC’s acknowledgement of responsibility for the behavior of
      its employees, and its agreement to pay a monetary penalty. The DOJ will refrain
      from seeking an indictment or otherwise initiating criminal prosecution of
      FENOC
      for all conduct related to the statement of facts attached to the deferred
      prosecution agreement, as long as FENOC remains in compliance with the
      agreement, which FENOC fully intends to do. FENOC has agreed to pay a penalty
      of
      $28 million (which is not deductible for income tax purposes) which reduced
      FirstEnergy's earnings by $0.09 per common share in the fourth quarter of 2005.
      As part of the deferred prosecution agreement entered into with the DOJ,
      $4.35 million of that amount will be directed to community service
      projects.





On
      April 21,
      2005, the NRC issued a NOV and proposed a $5 million civil penalty related
      to the degradation of the Davis-Besse reactor vessel head issue described above.
      The Company accrued $1 million for a potential fine prior to 2005 and
      accrued the remaining liability for the Company's share of the proposed fine
      of
      $1.8 million during the first quarter of 2005. On September 14, 2005,
      FENOC filed its response to the NOV with the NRC. FENOC accepted full
      responsibility for the past failure to properly implement its boric acid
      corrosion control and corrective action programs. The NRC NOV indicated that
      the
      violations do not represent current licensee performance. FirstEnergy paid
      the
      penalty in the third quarter of 2005. 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.





Effective
      July 1, 2005, the NRC oversight panel for Davis-Besse was terminated and
      Davis-Besse returned to the standard NRC reactor oversight process. At that
      time, NRC inspections were augmented to include inspections to support the
      NRC's
      Confirmatory Order dated March 8, 2004 that was issued at the time of
      startup and to address an NRC White Finding related to the performance of the
      emergency sirens. By letter dated December 8, 2005, the NRC advised FENOC
      that the White Finding had been closed.




41


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





On
      April 4,
      2005, the NRC held a public meeting to discuss FENOC’s performance at the Perry
      Nuclear Power Plant as identified in the NRC's annual assessment letter to
      FENOC. Similar public meetings are held with all nuclear power plant licensees
      following issuance by the NRC of their annual assessments. According to the
      NRC,
      overall the Perry Plant operated "in a manner that preserved public health
      and
      safety" even though it remained under heightened NRC oversight. During the
      public meeting and in the annual assessment, the NRC indicated that additional
      inspections will continue and that the plant must improve performance to be
      removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action
      Matrix. By an inspection report dated January 18, 2006, the NRC closed one
      of the White Findings (related to emergency preparedness) which led to the
      multiple degraded cornerstones.





On
      May 26,
      2005, the NRC held a public meeting to discuss its oversight of the Perry Plant.
      While the NRC stated that the plant continued to operate safely, the NRC also
      stated that the overall performance had not substantially improved since the
      heightened inspection was initiated. The NRC reiterated this conclusion in
      its
      mid-year assessment letter dated August 30, 2005. On September 28,
      2005, the NRC sent a CAL to FENOC describing commitments that FENOC had made
      to
      improve the performance of Perry and stated that the CAL would remain open
      until
      substantial improvement was demonstrated. The CAL was anticipated as part of
      the
      NRC's Reactor Oversight Process. If performance does not improve, the NRC has
      a
      range of options under the Reactor Oversight Process, from increased oversight
      to possible impact to the plant’s operating authority. Although unable to
      predict a potential impact, its ultimate disposition could have a material
      adverse effect on FirstEnergy's or its subsidiaries' financial condition,
      results of operations and cash flows.





*Other
      Legal
      Matters*




Various
        lawsuits,
        claims (including claims for asbestos exposure) and proceedings related to
        the
        Company's normal business operations are pending against the Company and
        its
        subsidiaries. The most significant not otherwise discussed above are described
        herein.





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





The
      City of Huron
      filed a complaint against OE with the PUCO challenging the ability of electric
      distribution utilities to collect transition charges from a customer of a newly
      formed municipal electric utility. The complaint was filed on May 28, 2003,
      and OE timely filed its response on June 30, 2003. In a related filing, the
      Ohio Companies filed for approval with the PUCO a tariff that would specifically
      allow the collection of transition charges from customers of municipal electric
      utilities formed after 1998.
      An adverse ruling could negatively affect full recovery of transition charges
      by
      the utility. Hearings on the matter were held in August 2005. Initial briefs
      from all parties were filed on September 22, 2005 and reply briefs were
      filed on October 14, 2005. It is unknown when the PUCO will decide this
      case.





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





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





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 in FirstEnergy’s nuclear and
      non-nuclear generation assets being owned by NGC and FGCO, respectively. The
      generating plant interests transferred do not include CEI’s leasehold interests
      in certain of the plants that are currently subject to sale and leaseback
      arrangements with non-affiliates.





On
      October 24,
      2005, the Ohio 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, 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.




42


The
        difference
        (approximately $33.7 million) between the purchase price specified in the
        Master
        Facility Lease and the net book value at the date of transfer was charged
        to
        equity. FGCO also assumed certain assets and liabilities relating to the
        purchased units. As consideration, FGCO delivered to the Company a promissory
        note of approximately $383.1 million that is secured by a lien on the units
        purchased, bears interest at a rate per annum based on the weighted cost
        of
        CEI’s long-term debt (5.99%) and matures twenty years after the date of
        issuance. FGCO may pre-pay a portion of the promissory note through refunding
        from time to time of CEI’s outstanding pollution control debt. The timing of any
        refunding will be subject to market conditions and other factors.


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




The
        purchase price of the
        generation assets was the net book value as of September 30, 2005. The
        difference (approximately $31.6 million) between the purchase price of the
        generation assets and the net book value at the date of transfer was credited
        to
        equity. NGC also assumed CEI’s interest in associated decommissioning trust
        funds, other related assets and other liabilities associated with the
        transferred assets. In addition, CEI received a promissory note from NGC
        in the
        principal amount of approximately $1.0 billion, representing the net book
        value
        of the contributed assets as of September 30,
        2005, less
        other liabilities assumed. The note bears interest at a rate per annum based
        on
        CEI’s weighted average cost of long-term debt (5.99%), matures twenty years from
        the date of issuance, and is subject to prepayment at any time, in whole
        or in
        part, by NGC.


These
      transactions
      were pursuant to the Ohio Companies’ restructuring plans that were approved by
      the PUCO under applicable Ohio electric utility restructuring legislation.
      Consistent with the restructuring plans, generation assets that had been owned
      by the Ohio Companies were required to be separated from the regulated delivery
      business of those companies through transfer to a separate corporate entity.
      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 are
      expected to affect the Company's near-term future results with reductions in
      revenues and expenses. Revenues will be reduced due to the termination of the
      sale of its nuclear-generated KWH and the lease
      of its
      non-nuclear generation assets arrangements with FES. The Company's expenses
      will
      be lower due to thenuclear 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. The Company will retain a fossil
      generation KWH sales arrangement and the portion of expenses related to its
      retained leasehold interests in the Bruce Mansfield Plant. In addition, the
      Company will receive interest income from associated company notes receivable
      from FGCO and NGC for the transfer of its generation net assets. FES will
      continue to provide the Company's PLR requirements under revised purchased
      power
      arrangements for a three-year period beginning January 1, 2006 (see Note 9
      -
      Regulatory Matters).





The
      following table
      provides the value of assets transferred along with the related
      liabilities:





**Assets
                Transferred (In millions)**Property,
                plant and equipment
            
            $
            1,275Other
                property
                and investments
            
            
            446Current
                assets
            
            
            72Deferred
                charges
            
            
            -$
            1,793**Liabilities
                Related to Assets Transferred**Long-term
                debt
            
            $
            -Current
                liabilities
            
            
            -Noncurrent
                liabilities
            
            
            320$
            320**Net
                Assets Transferred**
            
            $
            1,473





43





**15.**
            **NEW
                ACCOUNTING STANDARDS AND INTERPRETATIONS:**





*FSP
      FAS 115-1
      and FAS 124-1, "The Meaning of Other-Than-Temporary Impairment and its
      Application to Certain Investments"*





Issued
      in November
      2005, FSP 115-1 and FAS 124-1 addresses the determination as to when an
      investment is considered impaired, whether that impairment is other than
      temporary, and the measurement of an impairment loss. The FSP finalized and
      renamed EITF 03-1 and 03-1-a to FSP FAS 115-1. This FSP will (1) nullify certain
      requirements of Issue 03-1 and supersedes EITF topic No. D-44, "Recognition
      of
      Other Than Temporary Impairment upon the Planned Sale of a Security Whose Cost
      Exceeds Fair Value," (2) clarify that an investor should recognize an impairment
      loss no later than when the impairment is deemed other than temporary, even
      if a
      decision to sell has not been made, and (3) be effective for
      other-than-temporary impairment and analyses conducted in periods beginning
      after September 15, 2005. The FSP requires prospective application with an
      effective date for reporting periods beginning after December 15, 2005. The
      Company is currently evaluating this FSP and any impact on its
      investments.





*EITF
      Issue
      04-13, "Accounting for Purchases and Sales of Inventory with the Same
      Counterparty"*





In
      September 2005,
      the EITF reached a final consensus on Issue 04-13 concluding that two or more
      legally separate exchange transactions with the same counterparty should be
      combined and considered as a single arrangement for purposes of applying
      APB 29, when the transactions were entered into "in contemplation" of one
      another. If two transactions are combined and considered a single arrangement,
      the EITF reached a consensus that an exchange of inventory should be accounted
      for at fair value. Although electric power is not capable of being held in
      inventory, there is no substantive conceptual distinction between exchanges
      involving power and other storable inventory. Therefore, the Company will adopt
      this EITF effective for new arrangements entered into, or modifications or
      renewals of existing arrangements, in interim or annual periods beginning after
      March 15, 2006.




*SFAS
                154 -
                “Accounting Changes and Error Corrections - a replacement of APB Opinion
                No. 20 and FASB Statement
                No. 3”*





In
      May 2005, the
      FASB issued SFAS 154 to change the requirements for accounting and
      reporting a change in accounting principle. It applies to all voluntary changes
      in accounting principle and to changes required by an accounting pronouncement
      when that pronouncement does not include specific transition provisions. This
      Statement requires retrospective application to prior periods’ financial
      statements of changes in accounting principle, unless it is impracticable to
      determine either the period-specific effects or the cumulative effect of the
      change. In those instances, this Statement requires that the new accounting
      principle be applied to the balances of assets and liabilities as of the
      beginning of the earliest period for which retrospective application is
      practicable and that a corresponding adjustment be made to the opening balance
      of retained earnings (or other appropriate components of equity or net assets
      in
      the statement of financial position) for that period rather than being reported
      in the Consolidated Statements of Income. This Statement also requires that
      a
      change in depreciation, amortization, or depletion method for long-lived,
      nonfinancial assets be accounted for as a change in accounting estimate affected
      by a change in accounting principle. The provisions of this Statement are
      effective for accounting changes and corrections of errors made in fiscal years
      beginning after December 15, 2005. The Company adopted this Statement
      effective January 1, 2006.





*SFAS
                153,
                “Exchanges of Nonmonetary Assets - an amendment of APB Opinion No.
                29”*





In
      December 2004,
      the FASB issued SFAS 153 amending APB 29, which was based on the
      principle that nonmonetary assets should be measured based on the fair value
      of
      the assets exchanged. The guidance in APB 29 included certain exceptions to
      that principle. SFAS 153 eliminates the exception from fair value
      measurement for nonmonetary exchanges of similar productive assets and replaces
      it with an exception for exchanges that do not have commercial substance. This
      Statement specifies that a nonmonetary exchange has commercial substance if
      the
      future cash flows of the entity are expected to change significantly as a result
      of the exchange. The provisions of this Statement are effective January 1,
      2006 for the Company. This FSP is not expected to have a material impact on
      the
      Company’s financial statements.





*SFAS
      151,
“Inventory Costs - an amendment of ARB No. 43, Chapter 4”*





In
      November 2004,
      the FASB issued SFAS 151 to clarify the accounting for abnormal amounts of
      idle facility expense, freight, handling costs and wasted material (spoilage).
      Previous guidance stated that in some circumstances these costs may be “so
      abnormal” that they would require treatment as current period costs.
      SFAS 151 requires abnormal amounts for these items to always be recorded as
      current period costs. In addition, this Statement requires that allocation
      of
      fixed production overheads to the cost of conversion be based on the normal
      capacity of the production facilities. The provisions of this statement are
      effective for inventory costs incurred by the Company beginning January 1,
      2006. The Company does not expect this statement to have a material impact
      on
      its financial statements.







44


**16.**
            **SUMMARY
                OF QUARTERLY FINANCIAL DATA
                (UNAUDITED):**





The
      following
      summarizes certain consolidated operating results by quarter for 2005 and
      2004.





**March
                31,**
            
            **June
                30,**
            
            **September
                30,**
            
            **December
                31,****Three
                Months Ended**
            
            **2005**
            
            **2005**
            
            **2005**
            
            **2005*****(In
                millions)***Operating
                Revenues
            
            $
            433.2
            
            $
            448.7
            
            $
            526.4
            
            $
            459.8Operating
                Expenses and Taxes
            
            
            387.1
            
            
            390.5
            
            
            409.4
            
            
            372.2Operating
                Income
            
            
            46.1
            
            
            58.2
            
            
            117.0
            
            
            87.6Other
                Income
            
            
            4.3
            
            
            9.3
            
            
            24.1
            
            
            14.2Net
                Interest
                Charges
            
            
            34.9
            
            
            28.8
            
            
            30.7
            
            
            35.3Income
                Before
                Cumulative Effect of AccountingChange
            
            
            15.5
            
            
            38.7
            
            
            110.4
            
            
            66.5Cumulative
                Effect of Accounting Change (Net ofIncome
                Tax
                Benefit)
            
            
            -
            
            
            -
            
            
            -
            
            
            (3.7
            )Net
                Income
            
            $
            15.5
            
            $
            38.7
            
            $
            110.4
            
            $
            62.8Earnings
                on
                Common Stock
            
            $
            12.6
            
            $
            38.7
            
            $
            110.4
            
            $
            62.8





**March
                31,**
            
            **June
                30,**
            
            **September
                30,**
            
            **December
                31,****Three
                Months Ended**
            
            **2004**
            
            **2004**
            
            **2004**
            
            **2004*****(In
                millions)***Operating
                Revenues
            
            $
            426.5
            
            $
            440.9
            
            $
            504.9
            
            $
            436.2Operating
                Expenses and Taxes
            
            
            353.2
            
            
            363.5
            
            
            402.5
            
            
            361.4Operating
                Income
            
            
            73.3
            
            
            77.4
            
            
            102.4
            
            
            74.8Other
                Income
            
            
            11.7
            
            
            9.5
            
            
            8.3
            
            
            12.7Net
                Interest
                Charges
            
            
            36.6
            
            
            37.1
            
            
            28.3
            
            
            31.6Net
                Income
            
            $
            48.4
            
            $
            49.8
            
            $
            82.4
            
            $
            55.9Earnings
                on
                Common Stock
            
            $
            46.7
            
            $
            48.0
            
            $
            80.7
            
            $
            54.1





45