**THE
      TOLEDO
      EDISON COMPANY**





**2005
      ANNUAL
      REPORT TO STOCKHOLDERS**











The
      Toledo Edison
      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 2,500 square miles in northwestern Ohio. The area it serves has
      a
      population of approximately 0.8 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
            25-45











**GLOSSARY
      OF
      TERMS**





The
      following
      abbreviations and acronyms are used in this report to identify The Toledo Edison
      Company and its affiliates:


ATSI
              American
                  Transmission Systems, Inc., owns and operates transmission
                  facilitiesCEI
              The
                  Cleveland
                  Electric Illuminating Company, an affiliated Ohio electric utilityCFC
              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 CompanyTECC
              Toledo
                  Edison
                  Capital Corporation, a 90% owned subsidiary of
                  TE






The
      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 ObligationCO2
              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 FASB Statement 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
              FASB
                  Staff
                  Position No. 115-1 and FAS 124-1, "The Meaning of
                  Other-Than-TemporaryFAS
                  124-1
              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
              Letter
                of
                CreditMedicare
                  Act
              Medicare
                  Prescription Drug, Improvement and Modernization Act of
                  2003







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






MISO
            Midwest
                Independent Transmission System Operator, Inc.Moody’s
            Moody’s
                Investors ServiceMSG
            Market
                Support
                GenerationMW
            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 andExtinguishment
                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
                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
      Toledo Edison 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 Toledo Edison Company and its subsidiary 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. 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
                  TOLEDO EDISON COMPANY****SELECTED
                  FINANCIAL DATA****2005**
              
              **2004**
              
              **2003**
              
              **2002**
              
              **2001*****(Dollars
                  in thousands)*****GENERAL
                  FINANCIAL INFORMATION:**Operating
                  Revenues
              
              $
              1,040,186
              
              $
              1,008,112
              
              $
              932,335
              
              $
              996,045
              
              $
              1,086,503Operating
                  Income
              
              $
              74,505
              
              $
              93,075
              
              $
              35,660
              
              $
              36,699
              
              $
              85,964Income
                  (Loss)
                  Before Cumulative Effectof
                  Accounting
                  Change
              
              $
              76,164
              
              $
              86,283
              
              $
              19,930
              
              $
              (5,142
              )
              $
              42,691Net
                  Income
                  (Loss)
              
              $
              76,164
              
              $
              86,283
              
              $
              45,480
              
              $
              (5,142
              )
              $
              42,691Earnings
                  (Loss) on Common Stock
              
              $
              68,369
              
              $
              77,439
              
              $
              36,642
              
              $
              (15,898
              )
              $
              26,556Total
                  Assets
              
              $
              2,101,965
              
              $
              2,825,477
              
              $
              2,849,605
              
              $
              2,855,725
              
              $
              2,869,751**CAPITALIZATION
                  AS OF DECEMBER 31:**Common
                  Stockholder’s Equity
              
              $
              863,426
              
              $
              835,327
              
              $
              749,521
              
              $
              681,195
              
              $
              629,805Preferred
                  Stock Not Subject to MandatoryRedemption
              
              
              96,000
              
              
              126,000
              
              
              126,000
              
              
              126,000
              
              
              126,000Long-Term
                  Debt
              
              
              237,753
              
              
              300,299
              
              
              270,072
              
              
              557,265
              
              
              646,174Total
                  Capitalization
              
              $
              1,197,179
              
              $
              1,261,626
              
              $
              1,145,593
              
              $
              1,364,460
              
              $
              1,401,979**CAPITALIZATION
                  RATIOS:**Common
                  Stockholder’s Equity
              
              
              72.1
              %
              
              66.2
              %
              
              65.4
              %
              
              49.9
              %
              
              44.6
              %Preferred
                  Stock Not Subject to MandatoryRedemption
              
              
              8.0
              
              
              10.0
              
              
              11.0
              
              
              9.2
              
              
              9.0Long-Term
                  Debt
              
              
              19.9
              
              
              23.8
              
              
              23.6
              
              
              40.9
              
              
              46.4Total
                  Capitalization
              
              
              100.0
              %
              
              100.0
              %
              
              100.0
              %
              
              100.0
              %
              
              100.0
              %**DISTRIBUTION
                  KWH DELIVERIES (Millions):**Residential
              
              
              2,543
              
              
              2,316
              
              
              2,312
              
              
              2,427
              
              
              2,258Commercial
              
              
              2,937
              
              
              2,796
              
              
              2,771
              
              
              2,702
              
              
              2,667Industrial
              
              
              5,110
              
              
              5,006
              
              
              5,097
              
              
              5,280
              
              
              5,397Other
              
              
              64
              
              
              56
              
              
              69
              
              
              57
              
              
              61Total
              
              
              10,654
              
              
              10,174
              
              
              10,249
              
              
              10,466
              
              
              10,383**CUSTOMERS
                  SERVED:**Residential
              
              
              275,226
              
              
              273,800
              
              
              270,258
              
              
              272,474
              
              
              270,589Commercial
              
              
              37,803
              
              
              36,710
              
              
              36,969
              
              
              32,037
              
              
              31,680Industrial
              
              
              224
              
              
              211
              
              
              215
              
              
              1,883
              
              
              1,898Other
              
              
              564
              
              
              504
              
              
              451
              
              
              468
              
              
              443Total
              
              
              313,817
              
              
              311,225
              
              
              307,893
              
              
              306,862
              
              
              304,610**Number
                  of Employees**
              
              
              431
              
              
              414
              
              
              446
              
              
              508
              
              
              507




2


**THE
      TOLEDO
      EDISON 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
      their 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.


3


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 to 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 the generated KWH sales arrangement and the portion of expenses
      related to our retained leasehold interests in the Bruce Mansfield Plant and
      Beaver Valley Unit 2. 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).





**Results
      of
      Operations**





Earnings
      on common
      stock decreased to $68 million in 2005 from $77 million in 2004. This
      decrease resulted primarily from higher nuclear and other operating costs.
      These
      reductions to earnings were partially offset by higher operating revenues,
      lower
      purchased power costs and increased deferrals of new regulatory assets.





Earnings
      on common
      stock increased to $77 million in 2004 from $37 million in 2003.
      Earnings on common stock in 2003 included an after-tax gain of $26 million
      from the cumulative effect of an accounting change due to the adoption of
      SFAS 143. Income before the cumulative effect increased to $86 million
      from $20 million in 2003. This increase resulted primarily from the restart
      of the Davis-Besse Nuclear Power Station in April 2004 that contributed to
      higher operating revenues and lower nuclear operating costs; interest charges
      were also lower in 2004. These factors were partially offset by higher fuel
      and
      purchased power costs, other operating costs and depreciation and amortization
      costs.





*Operating
                Revenues*





Operating
      revenues
      increased by $32 million or 3.2% in 2005 from 2004. The
      higher revenues
      resulted from increased retail generation revenues of $45 million,
      partially offset by a $5 million decrease in distribution revenues, a
      $4 million decrease in wholesale sales revenue and an increase in shopping
      incentive credits of $4 million. Retail generation revenues increased in
      all customer classes (residential - $2 million, commercial -
      $5 million, industrial - $38 million). Industrial revenues primarily
      increased as a result of higher unit prices and an increase in KWH sales of
      1.5%. Higher KWH sales to industrial customers were partially offset by a slight
      increase in customer shopping .
      Generation
      services provided to industrial customers by alternative suppliers as a percent
      of total industrial sales delivered in our service area increased by 0.5
      percentage point. Higher
      residential
      and commercial revenues resulted from increased KWH sales (6.0% and 11.1%,
      respectively), as the result of warmer summer weather, which increased air
      conditioning loads, and higher unit prices. The increase in 2005 in commercial
      KWH sales reflected a 2.9 percentage point reduction in customer shopping while
      the residential KWH sales increase was moderated by a 2.0 percentage point
      increase in customer shopping.





The
      $5 million
      decrease in distribution revenues in 2005 was
      due to lower
      industrial revenues ($26 million), partially offset by increases in
      residential and commercial revenues ($15 million and $4 million,
      respectively). The impact from lower industrial sales unit prices more than
      offset the higher KWH sales in all customer classes.





Operating
      revenues
      increased by $76 million or 8.1% in 2004 from 2003. The increase in
      revenues resulted principally from a $98 million increase in wholesale
      sales revenue (primarily to FES) due to increased nuclear generation available
      for sale, partially offset by a $6 million decrease in retail generation
      revenues from franchise customers and $5 million of shopping incentive
      credits discussed below. Reduced retail generation revenues (residential -
      $4 million and commercial - $5 million) in 2004 reflected increases in
      shopping by residential and commercial customers of 6.9 percentage points
      and 2.5 percentage points, respectively, while shopping by industrial customers
      decreased slightly. Increased industrial customer generation revenue of
      $3 million was due to higher unit prices offsetting a 1.5% decrease in KWH
      sales.





Distribution
      revenues decreased by $7 million in 2004 compared to 2003, primarily as a
      result of lower unit prices in all customer sectors. Distribution deliveries
      in
      aggregate to the industrial and commercial sectors decreased and deliveries
      to
      residential customers were nearly unchanged in 2004 as compared to
      2003.





Under
      our Ohio
      transition plan, we provided incentives to customers to encourage shopping
      from
      alternative energy providers. The additional credits increased in 2005 and
      2004
      by $4 million and $5 million, respectively, compared with the prior
      year. These revenue reductions are deferred for future recovery under our
      transition plan and do not affect current period earnings.





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


4





**Changes
                in KWH Sales**
            
            **2005**
            
            **2004****Increase
                (Decrease)**Electric
                Generation:Retail
            
            
            4.2
            %
            
            (3.8
            )%Wholesale
            
            
            2.3
            %
            
            69.0
            %**Total
                Electric Generation Sales**
            
            
            **3.1**
            %
            
            **26.2**
            %Distribution
                Deliveries:Residential
            
            
            9.8
            %
            
            0.2
            %Commercial
            
            
            5.1
            %
            
            0.9
            %Industrial
            
            
            2.1
            %
            
            (1.8
            )%**Total
                Distribution Deliveries**
            
            
            **4.7**
            %
            
            **(0.7**
            **)**%





*Operating
                Expenses and Taxes*





Total
      operating
      expenses and taxes increased by $51 million in 2005 and by $18 million
      in 2004. 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
            
            $
            18Purchased
                power costs
            
            
            (16
            )
            
            12Nuclear
                operating costs
            
            
            13
            
            
            (87
            )Other
                operating costs
            
            
            16
            
            
            27Provision
                for
                depreciation
            
            
            5
            
            
            4Amortization
                of regulatory assets
            
            
            17
            
            
            10Deferral
                of
                new regulatory assets
            
            
            (20
            )
            
            (11
            )General
                taxes
            
            
            3
            
            
            3Income
                taxes
            
            
            25
            
            
            42**Total
                operating expenses and taxes**
            
            **$**
            **51**
            
            **$**
            **18**





Higher
      fuel costs in
      2005, compared with 2004, resulted principally from increased fossil generation
      at the Mansfield Plant. Purchased power costs decreased in 2005, compared with
      2004, due to a 4.1% decrease in unit costs and a 1.1% decrease in KWH purchased
      due to the higher generation available in 2005. Increased nuclear operating
      costs in 2005 were due to expenses associated with the 74-day refueling outage
      at the Perry Plant and the 25-day refueling outage at Beaver Valley Unit 2
      in 2005 compared to no refueling outages in 2004. Other operating costs
      increased in 2005, compared to 2004, primarily due to the MISO Day 2
      expenses that began April 1, 2005, partially offset by lower vegetation
      management expenses and employee benefit costs.





Higher
      fuel costs in
      2004, compared with 2003, resulted principally from increased nuclear
      generation, which was up 109.4% due to the return of Davis-Besse from its
      extended outage. Purchased power costs increased in 2004, compared with 2003,
      due to higher unit costs partially offset by lower KWH purchased due to lower
      retail generation sales requirements. Decreased nuclear operating costs in
      2004
      were due to reduced incremental costs associated with the extended Davis-Besse
      outage, unplanned work performed during the Perry Plant's 56-day nuclear
      refueling outage in 2003 and the 28-day refueling outage at Beaver Valley
      Unit 2 in 2003. Other operating costs increased in 2004, compared to 2003,
      reflecting higher employee benefit costs.





Depreciation
      charges
      increased by $5 million in 2005 compared to 2004 primarily due to property
      additions and amortization of leasehold improvements. These increases were
      partially offset by lower depreciation on electric plant as a result of the
      non-nuclear generation asset transfer on October 24, 2005 and the effect of
      revised service life assumptions for fossil-fired generating plants (for the
      2005 period prior to the asset transfer). Depreciation charges increased by
      $4 million in 2004 compared to 2003 due to a higher level of depreciable
      property in 2004.





The
      increase in
      charges for amortization of regulatory assets in 2005 and 2004, compared to
      the
      prior years, reflected increases in transition cost amortization. The higher
      deferrals of new regulatory assets in 2005 compared to the prior year were
      primarily due to higher shopping incentives ($4 million) and related
      interest ($3 million) in 2005 and the deferral of $12 million of MISO
      expenses and related interest that began in the second quarter of 2005. The
      higher deferrals of new regulatory assets in 2004 compared to the prior year
      were due to higher shopping incentives ($5 million) and related interest
      ($6 million) in 2004.





General
      taxes
      increased $3 million in 2005 primarily due to increases in real estate,
      personal property and other taxes. General taxes increased $3 million in
      2004 primarily due to the absence of settled property tax claims in 2003.


5


Income
        taxes
        increased $25 million in 2005 primarily due to Ohio deferred tax adjustments
        and
        an increase in taxable income. Income taxes increased $42 million in 2004
        primarily due to an increase in taxable income. In 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 $18 million, which was partially
        offset by the initial phase-out of the Ohio income-based franchise tax, which
        reduced income taxes by approximately $1 million in 2005.





*Other
      Income*





Other
      Income
      increased by $2 million in 2004, compared to 2003, due to $16 million
      of interest income from Shippingport Capital Trust (see Note 6 - Variable
      Interest Entities) beginning in 2004 partially offset by the absence of the
      $12 million NRG settlement in 2003.





*Net
                Interest Charges*





Net
      interest charges
      continued to trend lower, decreasing by $9 million in 2005 and
      $7 million in 2004, compared to the prior year, reflecting redemptions and
      refinancing activity. In 2005, we refinanced $45 million of pollution control
      notes. An additional $91 million of pollution control notes were refinanced
      by
      NGC as part of the nuclear generation asset transfer. We also optionally
      redeemed $30 million of preferred stock in 2005. We redeemed
      $230 million of long-term debt and repriced $121 million of pollution
      control notes during 2004.





*Cumulative
      Effect of Accounting Change*





Upon
      adoption of
      SFAS 143 in the first quarter of 2003, we recorded an after-tax gain to net
      income of $26 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
      $44 million increase to income, or $26 million net of income
      taxes.





**Capital
      Resources and Liquidity**





Our
      cash
      requirements in 2005 for operating expenses and construction expenditures were
      met without increasing our net debt and preferred stock outstanding. During
      2006
      and thereafter, we expect to meet our contractual obligations with a combination
      of cash from operations and funds from the capital markets. In connection with
      a
      plan to realign our capital structure, we plan to issue up to $100 million
      of
      new long-term debt in 2006. The proceeds are expected to be used as a return
      of
      equity capital to FirstEnergy.





*Changes
      in Cash
      Position*





As
      of
      December 31, 2005, we had $15,000 of cash and cash equivalents, which
      remained unchanged from December 31, 2004.





*Cash
      Flows From
      Operating Activities*





Net
      cash provided
      from operating activities was $156 million in 2005, $183 million in
      2004 and $61 million in 2003, summarized as follows:





**Operating
                Cash Flows**
            
            **2005**
            
            **2004**
            
            **2003*****(In
                millions)***Cash
                earnings(1)
            
            $
            211
            
            $
            240
            
            $
            119Pension
                trust
                contribution(2)
            
            
            (14
            )
            
            (8
            )
            
            -Working
                capital and other
            
            
            (41
            )
            
            (49
            )
            
            (58
            )Net
                cash
                provided fromoperating
                activities
            
            $
            156
            
            $
            183
            
            $
            61





(1)
            Cash
                earnings
                is a Non-GAAP measure (see reconciliation
                below).


(2)
            Pension
                trust
                contributions in 2005 and 2004 are net of $6 million and
                $5 million of income tax benefits,
                respectively.


6


Cash
      earnings, as
      disclosed in the table above, are not a measure of performance calculated in
      accordance with GAAP. We believe that cash earnings is 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)
            
            $
            76
            
            $
            86
            
            $
            45Non-Cash
                Charges (Credits):Provision
                for
                depreciation
            
            
            63
            
            
            58
            
            
            55Amortization
                of regulatory assets
            
            
            141
            
            
            124
            
            
            114Deferral
                of
                new regulatory assets
            
            
            (59
            )
            
            (39
            )
            
            (28
            )Nuclear
                fuel
                and capital lease amortization
            
            
            18
            
            
            25
            
            
            9Amortization
                of electric service obligation
            
            
            (5
            )
            
            -
            
            
            -Deferred
                rents
                and lease market valuation liability
            
            
            (30
            )
            
            (23
            )
            
            (37
            )Deferred
                income taxes and investment tax credits, net*
            
            
            (6
            )
            
            2
            
            
            (14
            )Accrued
                compensation and retirement benefits
            
            
            5
            
            
            7
            
            
            1Cumulative
                effect of accounting changes
            
            
            -
            
            
            -
            
            
            (26
            )Tax
                refund
                related to pre-merger period
            
            
            8
            
            
            -
            
            
            -Cash
                earnings
                (Non-GAAP)
            
            $
            211
            
            $
            240
            
            $
            119





*
            Excludes
                $5
                million of deferred tax benefits from pension contribution in
                2004.





Net
      cash provided
      from operating activities decreased $27 million in 2005 from 2004 as a
      result of a $29 million decrease for the reasons described above under
“Results of Operations” and a $6 million increase in after-tax voluntary
      pension trust contributions in 2005 as compared to 2004, partially offset by
      an
      $8 million increase from changes in working capital and other. The increase
      in cash provided from working capital and other was primarily due to
      $38 million of funds received in 2005 for prepaid electric service (under a
      three-year Energy for Education Program with the Ohio Schools Council),
      partially offset by increased cash outflows from accounts payable of
      $22 million, primarily to FESC.





Net
      cash provided
      from operating activities increased $122 million in 2004 from 2003 as a
      result of a $121 million increase in cash earnings as described above under
“Results of Operations” and a $9 million increase from changes in working
      capital and other. These increases were partially offset by the $8 million
      after-tax voluntary pension trust contribution in 2004.





*Cash
      Flows From
      Financing Activities*





In
      2005 and 2004,
      net cash used for financing activities of $211 million and
      $94 million, respectively, and in 2003, $7 million net cash provided
      from financing activities, primarily reflected the new issues and redemptions
      shown below:





**Securities
                Issued or Redeemed**
            
            **2005**
            
            **2004**
            
            **2003*****(In
                millions)******New
                Issues:***Pollution
                Control Notes
            
            $
            45
            
            $
            104
            
            $
            -***Redemptions:***Pollution
                Control Notes
            
            $
            136
            
            $
            -
            
            $
            -Unsecured Notes
            
            
            -
            
            
            -
            
            
            7Secured
                Notes
            
            
            -
            
            
            261
            
            
            183Preferred Stock
            
            
            30
            
            
            -
            
            
            -Other, principally redemption premiums
            
            
            3
            
            
            1
            
            
            1$
            169
            
            $
            262
            
            $
            191Short-term
                Borrowings, Net
            
            $
            (9
            )
            $
            74
            
            $
            206





Net
      cash used for
      financing activities increased $117 million in 2005 from 2004. The increase
      primarily resulted from a net increase of $49 million of net debt
      redemptions shown above and $70 million of common stock dividends to
      FirstEnergy in 2005.





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


7


We
      had
      $43 million
      of cash and
      temporary investments (which include short-term notes receivable from associated
      companies) and approximately $65 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). As of December 31,
      2005, we had the capability to issue $620 million of additional FMB on the
      basis of property additions and retired bonds under the terms of our mortgage
      indenture. Based upon applicable earnings coverage tests, we could issue up
      to
      $1.1 billion of preferred stock (assuming no additional debt was issued as
      of December 31, 2005).





On
      June 14,
      2005, we, FirstEnergy, OE, Penn, CEI, 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 will 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 approval.





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





The
      revolving credit
      facility contains financial covenants requiring each borrower to maintain a
      consolidated debt to total capitalization ratio of no more than 65%. As of
      December 31, 2005, our debt to total capitalization as defined under the
      revolving credit facility, was 28%.





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.





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 securities is stable. The ratings outlook from Moody’s and Fitch
      on all securities is positive.





**Ratings
                of Securities**
            
            **Securities**
            
            **S&P**
            
            **Moody’s**
            
            **Fitch****FirstEnergy**
            
            Senior
                unsecured
            
            BBB-
            
            Baa3
            
            BBB-**TE**
            
            Senior
                secured
            
            BBB
            
            Baa2
            
            BBB-Preferred
                stock
            
            BB+
            
            Ba2
            
            BB





*Cash
      Flows From
      Investing Activities*





Net
      cash provided
      from investing activities increased to $55 million in 2005 from a net use
      of cash for investing activities of $91 million in 2004. This change was
      primarily due to increased loan activity with associated companies. The
      $552 million increase in collection of principal amounts on long-term notes
      receivable in 2005 included $429 million from NGC and $123 million
      from FGCO. The $429 million received from NGC related to the nuclear generation
      asset transfer that occurred on December 16, 2005. The $123 million received
      from FGCO related to a balloon payment received in May 2005 for the gas-fired
      combustion turbines sold in 2001. This increase in collection from associated
      companies was partially offset by $409 million in loan payments to the money
      pool, compared to $7 million in loan repayments from associated companies in
      2004.


8


Net
      cash used for
      investing activities increased to $91 million in 2004 from $86 million
      in 2003. This increase was primarily due to the change in the investment in
      lessor notes, partially offset by lower property additions.





Our
      capital spending
      for the period 2006-2010 is expected to be about $228 million, of which
      approximately $54 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 were as follows:





**2007-**
            
            **2009-****Contractual
                Obligations**
            
            **Total**
            
            **2006**
            
            **2008**
            
            **2010**
            
            **Thereafter*****(In
                millions)***Long-term
                debt(1)
            
            $
            291
            
            $
            -
            
            $
            30
            
            $
            -
            
            $
            261Short-term
                borrowings
            
            
            65
            
            
            65
            
            
            -
            
            
            -
            
            
            -Operating
                leases(2)
            
            
            857
            
            
            84
            
            
            150
            
            
            148
            
            
            475Purchases(3)
            
            
            230
            
            
            36
            
            
            69
            
            
            63
            
            
            62Total
            
            $
            1,443
            
            $
            185
            
            $
            249
            
            $
            211
            
            $
            798





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


(2)
            Operating
                lease payments are net of capital trust receipts of $276.8 million
                (see Note 5).


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





**Off-Balance
      Sheet Arrangements**





Obligations
      not
      included on our Consolidated Balance Sheet primarily consist of sale and
      leaseback arrangements involving the Bruce Mansfield Plant and Beaver Valley
      Unit 2,
      which are
      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 $539 million.





**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 and debt obligations:





**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 Cash
              and
                Cash
                Equivalents-Fixed
                Income
            
            $
            12
            
            $
            9
            
            $
            15
            
            $
            12
            
            $
            19
            
            $
            617
            
            $
            684
            
            $
            636Average
                interest rate
            
            
            7.7
            %
            
            7.7
            %
            
            7.7
            %
            
            7.7
            %
            
            7.7
            %
            
            5.4
            %
            
            5.6
            %LiabilitiesLong-term
                Debt
                and OtherLong-Term
                Obligations:Fixed
                rate
            
            
            
            
            $
            30
            
            
            
            
            
            
            
            
            
            
            $
            14
            
            $
            44
            
            $
            45Average
                interest rate
            
            
            
            
            
            7.1
            %
            
            
            
            
            
            
            
            
            
            
            5.9
            %
            
            6.7
            %Variable
                rate
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            $
            247
            
            $
            247
            
            $
            248Average
                interest rate
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            3.3
            %
            
            3.3
            %Short-term
                Borrowings
            
            $
            65
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            $
            65
            
            $
            65Average
                interest rate
            
            
            4.0
            %
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            4.0
            %





9


**Equity
      Price
      Risk**





Included
      in our
      nuclear decommissioning trust investments are marketable equity securities
      carried at their market value of approximately
      $188 million as of December 31, 2004. There were no marketable equity
      securities in the trust investments as of December 31, 2005. As discussed
      in Note 4 - Fair Value of Financial Instruments, our nuclear
      decommissioning trust investments were transferred to NGC as part of the
      intra-system generation asset transfers with the exception of an amount related
      to our retained leasehold interests in Beaver Valley Unit 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 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. Our regulatory assets as of December 31, 2005 and 2004
      were $287 million and $366 million, respectively.





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:




·
              Maintain
                  our
                  existing level of base distribution rates through December 31,
                  2008,
 
 ·
              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,
                  2008;
 
 ·
              Reduce
                  our
                  deferred shopping incentive balances as of January 1, 2006 by up to
                  $45 million by accelerating the application of our accumulated
                  cost of
                  removal regulatory liability; and
 
 ·
              Recover
                  increased fuel costs of up to $75 million, $77 million, and $79
                  million,
                  in 2006, 2007, and 2008, respectively, from all OE and TE distribution
                  and
                  transmission customers through a fuel recovery mechanism. We may
                  defer and
                  capitalize increased fuel costs above the amount collected through
                  the
                  fuel recovery mechanism (in lieu of implementation of the GCAF
                  rider).


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





**Amortization****Period**
            
            **Amortization*****(In
                millions)***2006
            
            $
            802007
            
            
            892008
            
            
            100**Total
                Amortization**
            
            **$**
            **269**





10


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 $8 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.





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.


11


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.





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 $0.2 million as of December 31, 2005.


12


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





*Other
      Legal
      Proceedings*





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





*Power
                Outages and Related
                Litigation-*





On
      August 14,
      2003, various states and parts of southern Canada experienced widespread power
      outages. The outages affected approximately 1.4 million customers in
      FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s
      final report in April 2004 on the outages 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.





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 carrier seeks reimbursement
      from various FirstEnergy companies (and, in one case, from PJM, MISO and
      American Electric Power Company, Inc. as well) for claims paid to insureds
      for
      claims allegedly 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.


13


*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. Excluding our retained leasehold
      interests in Beaver Valley Unit 2 (18.26%), the transfer consisted of our
      prior owned interests in Beaver Valley Unit 2 (1.65%), Davis-Besse (48.62%)
      and Perry (19.91%).





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 $1.7 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.





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.


14


*Other
      Legal
      Matters-*





On
      October 20,
      2004, FirstEnergy was notified by the SEC that the previously disclosed informal
      inquiry initiated by the SEC's Division of Enforcement in September 2003
      relating to the restatements in August 2003 of previously reported results
      by
      FirstEnergy and the Ohio Companies, and the Davis-Besse extended outage, have
      become the subject of a formal order of investigation. The SEC's formal order
      of
      investigation also encompasses issues raised during the SEC's examination of
      FirstEnergy and the Companies under the 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.





*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.


15


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 $20 million). As a result of our voluntary
      contribution and the increased market value of pension plan assets, we
      recognized a prepaid benefit cost of $36 million as of December 31,
      2005. As prescribed by SFAS 87, we eliminated our additional minimum
      liability of $20 million and its intangible asset of $5 million. In
      addition, the entire AOCL balance was credited by $8 million (net of
      $6 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 have significantly increased 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 TE'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%
              
              $
              0.3
              
              $
              0.2
              
              $
              0.5Long-term
                  return on assets
              
              
              Decrease
                  by
                  0.25%
              
              $
              0.3
              
              $
              -
              
              $
              0.3Health
                  care
                  trend rate
              
              
              Increase
                  by
                  1%
              
              
              na
              
              $
              1.4
              
              $
              1.4




*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).


16


The
      calculation of
      future cash flows is based on assumptions, estimates and judgement 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 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 $501 million 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
      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, 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.


17


*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 its financial
      statements.











18


**THE
                  TOLEDO EDISON COMPANY****CONSOLIDATED
                  STATEMENTS OF INCOME****For
                  the Years Ended December 31,**
              
              **2005**
              
              **2004**
              
              **2003*****(In
                  thousands)*****OPERATING
                  REVENUES (a) (Note 2(I))**
              
              $
              1,040,186
              
              $
              1,008,112
              
              $
              932,335**OPERATING
                  EXPENSES AND TAXES:**Fuel
              
              
              58,897
              
              
              50,892
              
              
              32,735Purchased
                  power (Note 2(I))
              
              
              296,720
              
              
              312,867
              
              
              300,804Nuclear
                  operating costs
              
              
              181,410
              
              
              168,401
              
              
              254,986Other
                  operating costs (Note 2(I))
              
              
              168,522
              
              
              152,879
              
              
              125,869Provision
                  for
                  depreciation
              
              
              62,486
              
              
              57,948
              
              
              54,524Amortization
                  of regulatory assets
              
              
              141,343
              
              
              123,858
              
              
              113,664Deferral
                  of
                  new regulatory assets
              
              
              (58,566
              )
              
              (38,696
              )
              
              (27,575
              )General
                  taxes
              
              
              57,108
              
              
              54,142
              
              
              50,742Income
                  taxes
                  (benefit)
              
              
              57,761
              
              
              32,746
              
              
              (9,074
              )Total
                  operating expenses and taxes
              
              
              965,681
              
              
              915,037
              
              
              896,675**OPERATING
                  INCOME**
              
              
              74,505
              
              
              93,075
              
              
              35,660**OTHER
                  INCOME (net of income taxes) (Notes 2(I) and 7)**
              
              
              22,683
              
              
              22,951
              
              
              20,558**NET
                  INTEREST CHARGES:**Interest
                  on
                  long-term debt
              
              
              16,811
              
              
              27,153
              
              
              38,874Allowance
                  for
                  borrowed funds used during construction
              
              
              (465
              )
              
              (3,696
              )
              
              (5,838
              )Other
                  interest
                  expense
              
              
              4,678
              
              
              6,286
              
              
              3,252Net
                  interest
                  charges
              
              
              21,024
              
              
              29,743
              
              
              36,288**INCOME
                  BEFORE CUMULATIVE EFFECT****OF
                  ACCOUNTING CHANGE**
              
              
              76,164
              
              
              86,283
              
              
              19,930Cumulative
                  effect of accounting change (net of income taxesof
                  $18,201,000) (Note 2(G))
              
              
              -
              
              
              -
              
              
              25,550**NET
                  INCOME**
              
              
              76,164
              
              
              86,283
              
              
              45,480**PREFERRED
                  STOCK DIVIDEND REQUIREMENTS**
              
              
              7,795
              
              
              8,844
              
              
              8,838**EARNINGS
                  ON COMMON STOCK**
              
              $
              68,369
              
              $
              77,439
              
              $
              36,642(a)
                  Includes
                  electric sales to associated companies of $300 million, $305 million
                  and
                  $212 million in 2005, 2004 and 2003, respectively.The
                  accompanying Notes to Consolidated Financial Statements are an
                  integral
                  part of these statements.
   19
  **THE
                    TOLEDO EDISON COMPANY****CONSOLIDATED
                    BALANCE SHEETS****As
                    of
                    December 31,**
                
                **2005**
                
                **2004*****(In
                    thousands)*****ASSETS****UTILITY
                    PLANT:**In
                    service
                
                $
                824,677
                
                $
                1,856,478Less
                    -
                    Accumulated provision for depreciation
                
                
                372,845
                
                
                778,864451,832
                
                
                1,077,614Construction
                    work in progress-Electric
                    plant
                
                
                33,920
                
                
                58,535Nuclear
                    fuel
                
                
                -
                
                
                15,99833,920
                
                
                74,533485,752
                
                
                1,152,147**OTHER
                    PROPERTY AND INVESTMENTS:**Investment
                    in
                    lessor notes (Note 5)
                
                
                178,798
                
                
                190,692Nuclear
                    plant
                    decommissioning trusts
                
                
                59,209
                
                
                297,803Long-term
                    notes receivable from associated companies
                
                
                441,432
                
                
                39,975Other
                
                
                1,781
                
                
                2,031681,220
                
                
                530,501**CURRENT
                    ASSETS:**Cash
                    and cash
                    equivalents
                
                
                15
                
                
                15Receivables-Customers
                
                
                2,209
                
                
                4,858Associated
                    companies
                
                
                16,311
                
                
                36,570Other
                
                
                6,410
                
                
                3,842Notes
                    receivable from associated companies
                
                
                43,095
                
                
                135,683Materials
                    and
                    supplies, at average cost
                
                
                -
                
                
                40,280Prepayments
                    and other
                
                
                1,059
                
                
                1,15069,099
                
                
                222,398**DEFERRED
                    CHARGES:**Goodwill
                
                
                501,022
                
                
                504,522Regulatory
                    assets
                
                
                287,095
                
                
                366,385Prepaid
                    pension costs
                
                
                35,566
                
                
                -Property
                    taxes
                
                
                18,047
                
                
                24,100Other
                
                
                24,164
                
                
                25,424865,894
                
                
                920,431$
                2,101,965
                
                $
                2,825,477**CAPITALIZATION
                    AND LIABILITIES****CAPITALIZATION
                    (See Consolidated Statements of Capitalization):**Common
                    stockholder's equity
                
                $
                863,426
                
                $
                835,327Preferred
                    stock
                
                
                96,000
                
                
                126,000Long-term
                    debt
                
                
                237,753
                
                
                300,2991,197,179
                
                
                1,261,626**CURRENT
                    LIABILITIES:**Currently
                    payable long-term debt
                
                
                53,650
                
                
                90,950Accounts
                    payable-Associated
                    companies
                
                
                46,386
                
                
                110,047Other
                
                
                2,672
                
                
                2,247Notes
                    payable
                    to associated companies
                
                
                64,689
                
                
                429,517Accrued
                    taxes
                
                
                49,344
                
                
                46,957Lease
                    market
                    valuation liability
                
                
                24,600
                
                
                24,600Other
                
                
                40,049
                
                
                53,055281,390
                
                
                757,373**NONCURRENT
                    LIABILITIES:**Accumulated
                    deferred income taxes
                
                
                221,149
                
                
                221,950Accumulated
                    deferred investment tax credits
                
                
                11,824
                
                
                25,102Lease
                    market
                    valuation liability
                
                
                243,400
                
                
                268,000Retirement
                    benefits
                
                
                40,353
                
                
                39,227Asset
                    retirement obligation
                
                
                24,836
                
                
                194,315Deferred
                    revenues - electric service programs
                
                
                32,606
                
                
                -Other
                
                
                49,228
                
                
                57,884623,396
                
                
                806,478**COMMITMENTS
                    AND CONTINGENCIES (Notes 5 and 13)**$
                2,101,965
                
                $
                2,825,477The
                    accompanying Notes to Consolidated Financial Statements are an
                    integral
                    part of these balance sheets.
   20
  **THE
                    TOLEDO EDISON COMPANY****CONSOLIDATED
                    STATEMENTS OF CAPITALIZATION****As
                    of
                    December 31,**
                **2005**
                
                **2004*****(Dollars
                    in thousands, except per share
                    amounts)*****COMMON
                    STOCKHOLDER'S EQUITY:**Common
                  stock, $5 par value, authorized 60,000 shares39,133,887
                    shares outstanding
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                $
                195,670
                
                $
                195,670Other
                    paid-in
                    capital
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                473,638
                
                
                428,559Accumulated
                    other comprehensive income (Note 2(F))
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                4,690
                
                
                20,039Retained
                    earnings (Note 10(A))
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                189,428
                
                
                191,059Total
                    common
                    stockholder's equity
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                863,426
                
                
                835,327**Number
                    of Shares**
                
                
                **Optional****Outstanding**
                
                
                **Redemption
                    Price****2005**
                
                
                **2004**
                
                
                **Per
                    Share**
                
                
                **Aggregate****PREFERRED
                    STOCK NOT SUBJECT TO****MANDATORY
                    REDEMPTION (Note 10(B)):**Cumulative,
                    $100 par value-Authorized
                    3,000,000 shares$4.25
                
                
                
                
                
                
                
                
                160,000
                
                
                160,000
                
                $
                104.63
                
                $
                16,740
                
                
                16,000
                
                
                16,000$4.56
                
                
                
                
                
                
                
                
                50,000
                
                
                50,000
                
                
                101.00
                
                
                5,050
                
                
                5,000
                
                
                5,000$4.25
                
                
                
                
                
                
                
                
                100,000
                
                
                100,000
                
                
                102.00
                
                
                10,200
                
                
                10,000
                
                
                10,000Total
                
                
                
                
                
                
                
                
                310,000
                
                
                310,000
                
                
                
                
                
                31,990
                
                
                31,000
                
                
                31,000Cumulative,
                    $25 par value-Authorized
                    12,000,000 shares$2.365
                
                
                
                
                
                
                
                
                1,400,000
                
                
                1,400,000
                
                
                27.75
                
                $
                38,850
                
                
                35,000
                
                
                35,000Adjustable
                    Series A
                
                
                
                
                
                
                
                
                -
                
                
                1,200,000
                
                
                
                
                
                -
                
                
                -
                
                
                30,000Adjustable
                    Series B
                
                
                
                
                
                
                
                
                1,200,000
                
                
                1,200,000
                
                
                25.00
                
                
                30,000
                
                
                30,000
                
                
                30,0002,600,000
                
                
                3,800,000
                
                
                
                
                
                68,850
                
                
                65,000
                
                
                95,000Total
                
                
                
                
                
                
                
                
                2,910,000
                
                
                4,110,000
                
                
                
                
                
                100,840
                
                
                96,000
                
                
                126,000**LONG-TERM
                    DEBT (Note 10(C)):**Secured
                    notes-7.130%
                    due
                    2007
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                30,000
                
                
                30,0007.625%
                    due
                    2020
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                -
                
                
                45,0007.750%
                    due
                    2020
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                -
                
                
                54,000* 
3.050%
                    due 2024
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                67,300
                
                
                67,3006.100%
                    due
                    2027
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                10,100
                
                
                10,1005.375%
                    due
                    2028
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                3,751
                
                
                3,751* 
3.400%
                    due 2033
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                30,900
                
                
                30,900* 
3.130%
                    due 2033
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                20,200
                
                
                20,200* 
3.150%
                    due 2033
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                30,500
                
                
                30,500* 
3.300%
                    due 2035
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                45,000
                
                
                -Total
                    secured
                    notes
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                237,751
                
                
                291,751Unsecured
                    notes-* 
3.540%
                    due 2030
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                34,850
                
                
                34,850* 
4.500%
                    due 2033
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                -
                
                
                31,600* 
3.620%
                    due 2033
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                18,800
                
                
                18,800* 
3.100%
                    due 2033
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                -
                
                
                5,700Total
                    unsecured notes
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                53,650
                
                
                90,950Net
                    unamortized premium on debt
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                2
                
                
                8,548Long-term
                    debt
                    due within one year
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                (53,650
                )
                
                (90,950
                )Total
                    long-term debt
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                237,753
                
                
                300,299**TOTAL
                    CAPITALIZATION**
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                $
                1,197,179
                
                $
                1,261,626*
                    Denotes
                    variable-rate issue with applicable year-end interest rate
                    shown.The
                    accompanying Notes to Consolidated Financial Statements are an
                    integral
                    part of these statements.
   21
  **THE
                    TOLEDO EDISON COMPANY****CONSOLIDATED
                    STATEMENTS OF COMMON STOCKHOLDER'S EQUITY****Accumulated****Other**
                
                **Other****Comprehensive**
                
                **Number**
                
                **Par**
                
                **Paid-In**
                
                **Comprehensive**
                
                **Retained****Income**
                
                **of
                    Shares**
                
                **Value**
                
                **Capital**
                
                **Income
                    (Loss)**
                
                **Earnings*****(Dollars
                    in thousands)***Balance,
                    January 1, 2003
                
                
                
                
                
                39,133,887
                
                $
                195,670
                
                $
                428,559
                
                $
                (20,012
                )
                $
                76,978Net
                    income
                
                $
                45,480
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                45,480Unrealized
                    gain on investments, netof
                    $13,908,000
                    of income taxes
                
                
                19,988
                
                
                
                
                
                
                
                
                
                
                
                19,988Minimum
                    liability for unfunded retirement benefits,net
                    of
                    $8,489,000 of income taxes.
                
                
                11,696
                
                
                
                
                
                
                
                
                
                
                
                11,696Comprehensive
                    income
                
                $
                77,164Cash
                    dividends
                    on preferred stock
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                (8,838
                )Balance,
                    December 31, 2003
                
                
                
                
                
                39,133,887
                
                
                195,670
                
                
                428,559
                
                
                11,672
                
                
                113,620Net
                    income
                
                $
                86,283
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                86,283Unrealized
                    gain on investments, netof
                    $5,246,000
                    of income taxes
                
                
                7,253
                
                
                
                
                
                
                
                
                
                
                
                7,253Minimum
                    liability for unfunded retirement benefits,net
                    of
                    $717,000 of income taxes.
                
                
                1,114
                
                
                
                
                
                
                
                
                
                
                
                1,114Comprehensive
                    income
                
                $
                94,650Cash
                    dividends
                    on preferred stock
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                (8,844
                )Balance,
                    December 31, 2004
                
                
                
                
                
                39,133,887
                
                
                195,670
                
                
                428,559
                
                
                20,039
                
                
                191,059Net
                    income
                
                $
                76,164
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                76,164Unrealized
                    loss on investments, netof
                    $(16,884,000) of income taxes
                
                
                (23,654
                )
                
                
                
                
                
                
                
                
                
                
                (23,654
                )Minimum
                    liability for unfunded retirement benefits,net
                    of
                    $5,836,000 of income taxes.
                
                
                8,305
                
                
                
                
                
                
                
                
                
                
                
                8,305Comprehensive
                    income
                
                $
                60,815Affiliated
                    company asset transfers
                
                
                
                
                
                
                
                
                
                
                
                45,060Restricted
                    stock units
                
                
                
                
                
                
                
                
                
                
                
                19Cash
                    dividends
                    on preferred stock
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                (7,795
                )Cash
                    dividends
                    on common stock
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                (70,000
                )Balance,
                    December 31, 2005
                
                
                
                
                
                39,133,887
                
                $
                195,670
                
                $
                473,638
                
                $
                4,690
                
                $
                189,428
   **CONSOLIDATED
                      STATEMENTS OF PREFERRED STOCK****Not
                      Subject to****Mandatory
                      Redemption****Number**
                  
                  **Carrying****of
                      Shares**
                  
                  **Value*****(Dollars
                      in thousands)***Balance,
                      January 1, 2003
                  
                  
                  4,110,000
                  
                  $
                  126,000Balance,
                      December 31, 2003
                  
                  
                  4,110,000
                  
                  
                  126,000Balance,
                      December 31, 2004
                  
                  
                  4,110,000
                  
                  
                  126,000Redemptions-Adjustable
                      Series A
                  
                  
                  (1,200,000
                  )
                  
                  (30,000
                  )Balance,
                      December 31, 2005
                  
                  
                  2,910,000
                  
                  $
                  96,000The
                      accompanying Notes to Consolidated Financial Statements are
                      an integral
                      part of these statements.
    22
  **THE
                      TOLEDO EDISON COMPANY****CONSOLIDATED
                      STATEMENTS OF CASH FLOWS****For
                      the Years Ended December 31,**
                  
                  **2005**
                  
                  **2004**
                  
                  **2003*****(In
                      thousands)*****CASH
                      FLOWS FROM OPERATING ACTIVITIES:**Net
                      income
                  
                  $
                  76,164
                  
                  $
                  86,283
                  
                  $
                  45,480Adjustments
                      to
                      reconcile net income to net cash fromoperating
                      activities-Provision
                      for
                      depreciation
                  
                  
                  62,486
                  
                  
                  57,948
                  
                  
                  54,524Amortization
                      of regulatory assets
                  
                  
                  141,343
                  
                  
                  123,858
                  
                  
                  113,664Deferral
                      of
                      new regulatory assets
                  
                  
                  (58,566
                  )
                  
                  (38,696
                  )
                  
                  (27,575
                  )Nuclear
                      fuel
                      and capital lease amortization
                  
                  
                  18,463
                  
                  
                  25,034
                  
                  
                  9,289Deferred
                      rents
                      and lease market valuation liability
                  
                  
                  (30,088
                  )
                  
                  (23,121
                  )
                  
                  (37,001
                  )Deferred
                      income taxes and investment tax credits, net
                  
                  
                  (6,519
                  )
                  
                  6,123
                  
                  
                  (14,638
                  )Accrued
                      compensation and retirement benefits
                  
                  
                  5,396
                  
                  
                  6,963
                  
                  
                  840Cumulative
                      effect of accounting change
                  
                  
                  -
                  
                  
                  -
                  
                  
                  (25,550
                  )Pension
                      trust
                      contribution
                  
                  
                  (19,933
                  )
                  
                  (12,572
                  )
                  
                  -Tax
                      refund
                      related to pre-merger period
                  
                  
                  8,164
                  
                  
                  -
                  
                  
                  -Decrease
                      (increase) in operating assets-Receivables
                  
                  
                  10,813
                  
                  
                  10,228
                  
                  
                  19,107Materials
                      and
                      supplies
                  
                  
                  (3,210
                  )
                  
                  (5,133
                  )
                  
                  1,481Prepayments
                      and other current assets
                  
                  
                  91
                  
                  
                  5,554
                  
                  
                  (3,249
                  )Increase
                      (decrease) in operating liabilities-Accounts
                      payable
                  
                  
                  (45,416
                  )
                  
                  (23,398
                  )
                  
                  (53,765
                  )Accrued
                      taxes
                  
                  
                  2,387
                  
                  
                  (8,647
                  )
                  
                  20,928Accrued
                      interest
                  
                  
                  (1,557
                  )
                  
                  (9,080
                  )
                  
                  (3,965
                  )Electric
                      service prepayment programs
                  
                  
                  32,605
                  
                  
                  -
                  
                  
                  -Other
                  
                  
                  (36,939
                  )
                  
                  (18,438
                  )
                  
                  (38,977
                  )Net
                      cash
                      provided from operating activities
                  
                  
                  155,684
                  
                  
                  182,906
                  
                  
                  60,593**CASH
                      FLOWS FROM FINANCING ACTIVITIES:**New
                      Financing-Long-term
                      debt
                  
                  
                  45,000
                  
                  
                  103,500
                  
                  
                  -Short-term
                      borrowings, net
                  
                  
                  -
                  
                  
                  73,565
                  
                  
                  206,300Redemptions
                      and Repayments-Preferred
                      stock
                  
                  
                  (30,000
                  )
                  
                  -
                  
                  
                  -Long-term
                      debt
                  
                  
                  (138,859
                  )
                  
                  (262,162
                  )
                  
                  (190,794
                  )Short-term
                      borrowings, net
                  
                  
                  (8,996
                  )
                  
                  -
                  
                  
                  -Dividend
                      Payments-Common
                      stock
                  
                  
                  (70,000
                  )
                  
                  -
                  
                  
                  -Preferred
                      stock
                  
                  
                  (7,795
                  )
                  
                  (8,844
                  )
                  
                  (8,844
                  )Net
                      cash
                      provided from (used for) financing activities
                  
                  
                  (210,650
                  )
                  
                  (93,941
                  )
                  
                  6,662**CASH
                      FLOWS FROM INVESTING ACTIVITIES:**Property
                      additions
                  
                  
                  (71,976
                  )
                  
                  (64,629
                  )
                  
                  (84,924
                  )Loan
                      repayments from (loans to) associated companies, net
                  
                  
                  (409,409
                  )
                  
                  7,081
                  
                  
                  (19,014
                  )Collection
                      of
                      principal on long-term notes receivable
                  
                  
                  552,613
                  
                  
                  203
                  
                  
                  188Investments
                      in
                      lessor notes (Note 5)
                  
                  
                  11,894
                  
                  
                  10,246
                  
                  
                  40,025Contributions
                      to nuclear decommissioning trusts
                  
                  
                  (28,541
                  )
                  
                  (28,541
                  )
                  
                  (28,541
                  )Other
                  
                  
                  385
                  
                  
                  (15,547
                  )
                  
                  6,560Net
                      cash
                      provided from (used for) investing activities
                  
                  
                  54,966
                  
                  
                  (91,187
                  )
                  
                  (85,706
                  )Net
                      change in
                      cash and cash equivalents
                  
                  
                  -
                  
                  
                  (2,222
                  )
                  
                  (18,451
                  )Cash
                      and cash
                      equivalents at beginning of year
                  
                  
                  15
                  
                  
                  2,237
                  
                  
                  20,688Cash
                      and cash
                      equivalents at end of year
                  
                  $
                  15
                  
                  $
                  15
                  
                  $
                  2,237**SUPPLEMENTAL
                      CASH FLOW INFORMATION:**Cash
                      Paid
                      During the Year-Interest
                      (net
                      of amounts capitalized)
                  
                  $
                  29,709
                  
                  $
                  40,082
                  
                  $
                  38,576Income
                      taxes
                      (refund)
                  
                  $
                  78,265
                  
                  $
                  53,728
                  
                  $
                  (9,257
                  )The
                      accompanying Notes to Consolidated Financial Statements are
                      an integral
                      part of these statements.
   23
   **THE
                    TOLEDO EDISON COMPANY****CONSOLIDATED
                    STATEMENTS OF TAXES****For
                    the Years Ended December 31,**
                
                
                
                **2005**
                
                **2004**
                
                **2003*****(In
                    thousands)*****GENERAL
                    TAXES:**Ohio
                    kilowatt-hour excise*
                
                
                
                
                $
                28,947
                
                $
                28,158
                
                $
                29,793Real
                    and
                    personal property
                
                
                
                
                
                25,030
                
                
                23,559
                
                
                18,488Social
                    security and unemployment
                
                
                
                
                
                2,365
                
                
                2,089
                
                
                1,861Other
                
                
                
                
                
                766
                
                
                336
                
                
                600Total
                    general
                    taxes
                
                
                
                
                $
                57,108
                
                $
                54,142
                
                $
                50,742**PROVISION
                    FOR INCOME TAXES:**Currently
                    payable-Federal
                
                
                
                
                $
                61,914
                
                $
                34,587
                
                $
                15,495State
                
                
                
                
                
                18,535
                
                
                11,640
                
                
                4,53780,449
                
                
                46,227
                
                
                20,032Deferred,
                    net-Federal
                
                
                
                
                
                (18,994
                )
                
                7,156
                
                
                4,414State
                
                
                
                
                
                14,875
                
                
                1,064
                
                
                1,205(4,119
                )
                
                8,220
                
                
                5,619Investment
                    tax
                    credit amortization
                
                
                
                
                
                (2,399
                )
                
                (2,097
                )
                
                (2,056
                )Total
                    provision for income taxes
                
                
                
                
                $
                73,931
                
                $
                52,350
                
                $
                23,595**INCOME
                    STATEMENT CLASSIFICATION****OF
                    PROVISION FOR INCOME TAXES:**Operating
                    income
                
                
                
                
                $
                57,761
                
                $
                32,746
                
                $
                (9,074
                )Other
                    income
                
                
                
                
                
                16,170
                
                
                19,604
                
                
                14,468Cumulative
                    effect of accounting change
                
                
                
                
                
                -
                
                
                -
                
                
                18,201Total
                    provision for income taxes
                
                
                
                
                $
                73,931
                
                $
                52,350
                
                $
                23,595**RECONCILIATION
                    OF FEDERAL INCOME TAX****EXPENSE
                    AT STATUTORY RATE TO TOTAL****PROVISION
                    FOR INCOME TAXES:**Book
                    income
                    before provision for income taxes
                
                
                
                
                $
                150,095
                
                $
                138,633
                
                $
                69,075Federal
                    income
                    tax expense at statutory rate
                
                
                
                
                $
                52,533
                
                $
                48,522
                
                $
                24,176Increases
                    (reductions) in taxes resulting from-State
                    income
                    taxes, net of federal income tax benefit
                
                
                
                
                
                21,716
                
                
                8,258
                
                
                3,732Amortization
                    of investment tax credits
                
                
                
                
                
                (2,399
                )
                
                (2,097
                )
                
                (2,056
                )Amortization
                    of tax regulatory assets
                
                
                
                
                
                (2,841
                )
                
                (2,492
                )
                
                (2,397
                )Other,
                    net
                
                
                
                
                
                4,922
                
                
                159
                
                
                140Total
                    provision for income taxes
                
                
                
                
                $
                73,931
                
                $
                52,350
                
                $
                23,595**ACCUMULATED
                    DEFERRED INCOME TAXES AS OF****DECEMBER
                    31:**Property
                    basis
                    differences
                
                
                
                
                $
                229,430
                
                $
                216,933
                
                $
                193,409Regulatory
                    transition charge
                
                
                
                
                
                54,719
                
                
                101,190
                
                
                151,129Asset
                    retirement obligations
                
                
                
                
                
                -
                
                
                14,703
                
                
                13,158Unamortized
                    investment tax credits
                
                
                
                
                
                (3,785
                )
                
                (9,606
                )
                
                (10,472
                )Deferred
                  gain
                  for asset sales - affiliated companies
                
                
                
                
                
                10,893
                
                
                11,111
                
                
                12,618Other
                    comprehensive income
                
                
                
                
                
                3,036
                
                
                14,084
                
                
                8,121Above
                    market
                    leases
                
                
                
                
                
                (104,998
                )
                
                (120,078
                )
                
                (130,231
                )Retirement
                    benefits
                
                
                
                
                
                6,527
                
                
                41
                
                
                (4,568
                )Shopping
                    incentive deferral
                
                
                
                
                
                43,926
                
                
                36,628
                
                
                21,416Other
                
                
                
                
                
                (18,599
                )
                
                (43,056
                )
                
                (52,626
                )Net
                    deferred
                    income tax liability
                
                
                
                
                $
                221,149
                
                $
                221,950
                
                $
                201,954*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 TE (Company) and its 90% owned subsidiary, TECC.
        TECC was formed in 1997 to make equity investments in a business trust in
        connection with financing related to the Bruce Mansfield Plant sale and leaseback
        transaction (see Note 5). CEI, an affiliate, has a 10% interest in TECC.
        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 CEI, OE, 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 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 will continue 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 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
            
            $
            191
            
            $
            327Customer
                shopping incentives
            
            
            132
            
            
            89Liabilities
                to
                customers - income taxes
            
            
            (5
            )
            
            (10
            )Gain
                on
                reacquired debt
            
            
            (4
            )
            
            (5
            )Employee
                postretirement benefit costs
            
            
            6
            
            
            7MISO
                transmission costs
            
            
            12
            
            
            -Asset
                removal
                costs
            
            
            (47
            )
            
            (41
            )Other
            
            
            2
            
            
            (1
            )Total
            
            $
            287
            
            $
            366


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
      ($132 million as of December 31, 2005) was reduced on January 1,
      2006 by $45 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, with full recovery expected to be
      completed for the Company as of December 31, 2008. At the end of the
      recovery period, any remaining unamortized regulatory transition costs and
      Extended RTC balance 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
      2008:





**Amortization****Period**
            
            **Amortization*****(In
                millions)***2006
            
            $
            802007
            
            
            892008
            
            
            100**Total
                Amortization**
            
            **$**
            **269**





**(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 $2 million (billed - $2 million) and $5 million
      (billed - $4 million and unbilled - $1 million) as of
      December 31, 2005 and 2004, respectively.





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





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





Utility
      plant
      reflects original cost of construction (except for the Company's leasehold
      interests in Beaver Valley Unit 2 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 3.1% in 2005 and 2.8% in 2004 and 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
        o n
        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. The impairment
        analysis includes a significant source of cash representing the Company's
        recovery of transition costs as described above under "Regulatory Matters."
        The
        Company estimates that completion of transition cost recovery will not result
        in
        an impairment of goodwill. As of December 31, 2005, the Company had
        approximately $501 million 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.




*Investments*





The
      Company
      periodically evaluates for impairment investments that include
      available-for-sale securities held by its nuclear decommissioning trusts. In
      accordance with SFAS 115, securities classified as available-for-sale are
      evaluated to determine whether a decline in fair value below the cost basis
      is
      other than temporary. If the decline in fair value is determined to be other
      than temporary, the cost basis of the security is written down to fair value.
      The Company considers, among other factors, the length of time and the extent
      to
      which the security's fair value has been less than cost and the near-term
      financial prospects of the security issuer when evaluating investments for
      impairment. The fair value and unrealized gains and losses of the Company's
      investments are disclosed in Note 4.





**(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, accumulated other comprehensive income consisted of
      unrealized gains on investments in securities available for sale of
      $ 5 million.
      As
      of December 31, 2004, accumulated other comprehensive income consisted of a
      minimum liability for unfunded retirement benefits of $8 million and
      unrealized gains on investments in securities available for sale of
      $28 million.





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





Results
      for 2003
      include an after-tax credit to net income of $25.6 million recorded by the
      Company upon adoption of SFAS 143 in January 2003. The Company identified
      applicable legal obligations as defined under the new accounting standard for
      nuclear power plant decommissioning and reclamation of a sludge disposal pond
      at
      the Bruce Mansfield Plant. As a result of adopting SFAS 143 in January
      2003, asset retirement costs of $41.1 million were recorded as part of the
      carrying amount of the related long-lived asset, offset by accumulated
      depreciation of $5.5 million. The asset retirement obligation liability at
      the date of adoption was $172 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 $179.6 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 $43.8 million increase to
      income, or $25.6 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 the Company
      recognizing any tax losses or credits it contributed 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,
      CEI,
      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, CEI, OE and Penn completed the intra-system transfers of
      their generation a ssets
      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 CEI. The primary affiliated companies transactions are as
      follows:





**2005**
            
            **2004**
            
            **2003*****(In
                millions)*****Operating
                Revenues:**PSA
                revenues
                from FES
            
            $
            195
            
            $
            204
            
            $
            103Generating
                units rent from FES
            
            
            12
            
            
            15
            
            
            15Electric
                sales
                to CEI
            
            
            105
            
            
            101
            
            
            109Ground
                lease
                with ATSI
            
            
            2
            
            
            2
            
            
            2**Services
                Received:**Purchased
                power under PSA
            
            
            295
            
            
            311
            
            
            298Transmission
                expenses
            
            
            -
            
            
            -
            
            
            19FESC
                support
                services
            
            
            34
            
            
            36
            
            
            35**Other
                Income:**Interest
                income from ATSI
            
            
            3
            
            
            3
            
            
            3Interest
                income from FES
            
            
            4
            
            
            10
            
            
            10Interest
                income from Shippingport (Note 6)
            
            
            15
            
            
            16
            
            
            -





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.





The
      Company is
      selling 150 megawatts of its Beaver Valley Unit 2 leased capacity
      entitlement to CEI. Operating revenues for this transaction were
      $105 million, $101 million and $109 million in 2005, 2004 and
      2003, respectively. This sale agreement is expected to continue through the
      end
      of the lease period (see Note 5).


28


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





FirstEnergy
      provides
      noncontributory defined benefit pension plans that cover substantially all
      of
      its employees. The trusteed plans provide defined benefits based on years of
      service and compensation levels. 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 cash
      contribution to its pension plan (Company’s share was $20 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 retired 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.





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


29





**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
            
            $
            36
            
            $
            17
            
            $
            (40
            )
            $
            (36
            )Decrease
                in
                minimum liability
              included
                in
                other comprehensive 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
            
            $
            3
            
            $
            5
            
            $
            9
            
            $
            7
            
            $
            6





**Weighted-Average
                Assumptions Used****to
                Determine Net Periodic Benefit Cost****for
                Years Ended December 31****Pension
                Benefits**
            
            **Other
                Benefits****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 $36 million as of
      December 31, 2005. As prescribed by SFAS 87, the Company eliminated
      its additional minimum liability of $20 million and its intangible asset of
      $5 million. In addition, the entire AOCL balance was credited by
      $8 million (net of $6 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**
            
            **Other****Benefits**
            
            **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
      -*





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 as of
      December 31:





**2005**
            
            **2004****Carrying**
            
            **Fair**
            
            **Carrying**
            
            **Fair****Value**
            
            **Value**
            
            **Value**
            
            **Value*****(In
                millions)***Long-term
                debt
            
            $
            291
            
            $
            293
            
            $
            383
            
            $
            390





The
      fair value of
      long-term debt reflects 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
            
            $
            59
            
            $
            59
            
            $
            78
            
            $
            78-Corporate
                debt securities
            
            
            625
            
            
            577
            
            
            393
            
            
            437684
            
            
            636
            
            
            471
            
            
            515Equity
                securities(1)
            
            
            2
            
            
            2
            
            
            190
            
            
            190$
            686
            
            $
            638
            
            $
            661
            
            $
            705





(1)
            Includes nuclear decommissioning trust
                investments.





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. Decommissioning trust investments are classified
      as available-for-sale securities. As part of the intra-system nuclear generation
      assets transfer in the fourth quarter of 2005, the Company transferred its
      decommissioning trust investments to NGC with the exception of a portion related
      to the leasehold interests in Beaver Valley Unit 2 retained by the Company.
      The Company has no securities held for trading purposes. The following table
      summarizes the amortized cost basis, gross unrealized gains and losses and
      fair
      values for decommissioning trust investments as of
      December 31:


32





**2005**
            
            **2004****Cost**
            
            **Unrealized**
            
            **Unrealized**
            
            **Fair**
            
            **Cost**
            
            **Unrealized**
            
            **Unrealized**
            
            **Fair****Basis**
            
            **Gains**
            
            **Losses**
            
            **Value**
            
            **Basis**
            
            **Gains**
            
            **Losses**
            
            **Value*****(In
                millions)***Debt
                securities
            
            $
            60
            
            $
            -
            
            $
            1
            
            $
            59
            
            $
            106
            
            $
            5
            
            $
            1
            
            $
            110Equity
                securities
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            143
            
            
            47
            
            
            2
            
            
            188$
            60
            
            $
            -
            
            $
            1
            
            $
            59
            
            $
            249
            
            $
            52
            
            $
            3
            
            $
            298








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
            
            $
            366
            
            $
            269
            
            $
            147Gross
                realized
                gains
            
            
            35
            
            
            22
            
            
            10Gross
                realized
                losses
            
            
            15
            
            
            13
            
            
            10Interest
                and
                dividend income
            
            
            9
            
            
            9
            
            
            7





The
      following table
      provides the fair value and gross unrealized losses of nuclear decommissioning
      trust investments that are deemed to be temporarily impaired as of
      December 31, 2005.





**Less
                Than 12 Months**
            
            **12
                Months or More**
            
            **Total****Fair**
            
            **Unrealized**
            
            **Fair**
            
            **Unrealized**
            
            **Fair**
            
            **Unrealized****Value**
            
            **Losses**
            
            **Value**
            
            **Losses**
            
            **Value**
            
            **Losses*****(In
                millions)***Debt
                securities
            
            $
            33
            
            $
            1
            
            $
            10
            
            $
            -
            
            $
            43
            
            $
            1








The
      Company
      periodically evaluates the securities held by its nuclear decommissioning trusts
      for other-than-temporary impairment. The Company considers the length of time
      and the extent to which the security's fair value has been less than its cost
      basis and other factors to determine whether an impairment is other than
      temporary.





Unrealized
      gains and
      losses applicable to the Company's decommissioning trusts are recognized in
      OCI
      in accordance with SFAS 115, as fluctuations in the fair value of these
      trust balances will eventually affect earnings.





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 CEI
      sold their ownership int erests
      in Bruce
      Mansfield Units 1, 2 and 3 and the Company 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 CEI entered into operating leases for
      lease terms of approximately 30 years as co-lessees. Subsequent to the
      intra-system generation assets transfers in the fourth quarter of 2005, the
      Company and CEI continue to be responsible, to the extent of their leasehold
      interests during the terms of the leases, for costs associated with the units
      including construction expenditures, operation and maintenance expenses,
      insurance, nuclear fuel, property taxes and decommissioning. The Company and
      CEI
      have the right, at the end of the respective basic lease terms, to renew the
      leases. The Company and CEI 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
      CEI, the Company is also obligated for CEI's lease payments. If CEI is unable
      to
      make its payments under the Bruce Mansfield Plant lease, the Company would
      be
      obligated to make such payments. No such payments have been made on behalf
      of
      CEI. (CEI's future minimum lease payments as of December 31,
      200 5
      were approximately $0.2 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:


33





**2005**
            
            **2004**
            
            **2003*****(In
                millions)***Operating
                leasesInterest
                element
            
            $
            43.9
            
            $
            46.4
            
            $
            49.5Other
            
            
            62.3
            
            
            52.9
            
            
            63.3Total
                rentals
            
            $
            106.2
            
            $
            99.3
            
            $
            112.8





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





**Operating
                Leases****Lease**
            
            **Capital****Payments**
            
            **Trust**
            
            **Net*****(In
                millions)***2006
            
            $
            109.7
            
            $
            26.1
            
            $
            83.62007
            
            
            101.0
            
            
            22.6
            
            
            78.42008
            
            
            98.6
            
            
            27.2
            
            
            71.42009
            
            
            99.8
            
            
            23.3
            
            
            76.52010
            
            
            100.0
            
            
            28.5
            
            
            71.5Years
                thereafter
            
            
            624.5
            
            
            149.1
            
            
            475.4Total
                minimum
                lease payments
            
            $
            1,133.6
            
            $
            276.8
            
            $
            856.8





The
      Company has
      recorded above-market lease lia bilities
      for Beaver
      Valley Unit 2 and the Bruce Mansfield Plant associated with the 1997 merger
      creating FirstEnergy. The total above-market lease obligation of
      $111 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 $6 million per year). The total above-market lease
      obligation of $298 million associated with the Bruce Mansfield Plant is
      being amortized on a straight-line basis through the end of 2016 (approximately
      $19 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 $268 million, of which $25 million is payable within one
      year.





The
      Company and CEI
      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 (Offering), the two companies
      pledged $720 million aggregate principal amount ($145 million for the
      Company and $575 million for CEI) 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 $906.5 million
      ($337.1 million for the Company and $569.4 million for CEI) in a
      business trust, in June 1997. The trust used these funds in July 1997 to
      purchase lease notes and redeem all $873.2 million aggregate principal
      amount of 10-1/4% and 11-1/8% secured lease obligations 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 (see Note 6 for FIN 46R discussion).





**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.





Shippingport
      was
      established to purchase all of the SLOBs issued in connection with the Company's
      and CEI's Bruce Mansfield Plant sale and leaseback transaction in 1987. The
      Company and CEI used debt and available funds to purchase the notes issued
      by
      Shippingport. Adoption of FIN 46R resulted in the consolidation of Shippingport
      by CEI as of December 31, 2003.





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
      concluded that it was not the primary beneficiary of the owner trusts and it
      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 applicable sale-leaseback agreements upon the
      occurrence of certain contingent events that the Company 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 agreements, the Company
      has net minimum discounted lease payments of $539 million, that would not
      be payable if the casualty value payments are made.


34






**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 - $12 million).





**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 $18 million,
      which was partially offset by the initial phase-out of the Ohio income-based
      franchise tax, which reduced income taxes by approximately $1 million in
      2005.





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





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 are relieved
      of their obligation to obtain PLR power requirements from FES if the Ohio
      competitive bid process results in a lower price for retail customers. A similar
      power sales agreement between FES and Penn permits Penn to obtain its PLR power
      requirements from FES at a fixed price equal to the retail generation price
      during 2006. Penn has filed a plan with the PPUC to use an RFP process to obtain
      its power supply requirements after 2006.





On
      December 29,
      2005, the FERC issued an order setting the two power sales agreements for
      hearing. The order 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 December 31, 2008
                for TE;





·
            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, 2008 for
                TE;





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





·
            Recover
                increased fuel costs of up to $75 million, $77 million, and $79 million,
                in 2006, 2007, and 2008, respectively, from all OE and TE distribution
                and
                transmission customers through a fuel recovery mechanism. The Company
                may
                defer and capitalize increased fuel costs above the amount collected
                through the fuel recovery mechanism (in lieu of implementation of
                the GCAF
                rider).


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 $8 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-**





Preferred
      stock may
      be redeemed by the Company in whole, or in part, with 30-90 days’
notice.





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


37


The
      preferred
      dividend rates on the Company’s Series B shares fluctuate based on
      prevailing interest rates and market conditions. The dividend rate averaged
      7%
      in 2005.





The
      Company has
      five million authorized and unissued shares of $25 par value
      preference stock.





**(C)**
            **LONG-TERM
                DEBT-**





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. There also exist cross-default provisions among
      financing arrangements of FirstEnergy and the Company.





Sinking
      fund
      requirements for FMB and maturing long-term debt for the next five years
      are:





***(In
                millions)***2006
            $
            542007
            
            302008
            
            -2009
            
            -2010
            
            -





Included
      in the
      table above are amounts for various variable interest rate long-term debt 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 $54 million in 2006, representing the next time the 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 $54 million and noncancelable
      municipal bond insurance policies of $198 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 1.625% of
      the
      amounts of the LOCs to the issuing bank and 0.213% to 0.370% 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 $30 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 CEI
      have unsecured LOCs of approximately $ 194 million
      in
      connection with the sale and leaseback of Beaver Valley Unit 2. The Company
      and CEI are jointly and severally liable for the LOCs (see
      Note 5).





**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.





The
      Company
      initially identified applicable legal obligations as defined under the standard
      for nuclear power plant decommissioning of Beaver Valley 2, and Perry
      nuclear generating facilities and reclamation of a sludge disposal pond related
      to the Bruce Mansfield Plant. The ARO liability as of the date of adoption
      was
      $172 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 sale and leaseback
      arrangements remain with the Company.


38


In
      2005, the Company
      revised the ARO associated with Beaver Valley Unit 2, Davis-Besse and Perry
      as a result of an updated decommissioning study. The present value of revisions
      in the estimated cash flows associated with projected decommissioning costs
      connected with the assets subject to sale and leaseback arrangements decreased
      the ARO and corresponding plant asset for Beaver Valley Unit 2 by
      $4 million.





The
      Company
      continues to maintain the nuclear decommissioning trust funds associated with
      the sale and leaseback arrangements that are legally restricted for purposes
      of
      settling the nuclear decommissioning ARO. As of December 31, 2005, the fair
      value of the decommissioning trust assets was $59 million.





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. Accounting for conditional ARO under FIN 47 is the same as
      described above for SFAS 143. The adoption of FIN 47 had an immaterial
      impact on the Company’s year ended December 31, 2005 results.





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





**ARO
                Reconciliation**
            
            **2005**
            
            **2004*****(In
                millions)***Balance
                at
                beginning of year
            
            $
            194
            
            $
            182Transfers
                to
                FGCO and NCG
            
            
            (157
            )
            
            -Accretion
            
            
            13
            
            
            12Revisions
                in
                estimated cash flows
            
            
            (26
            )
            
            -FIN
                47
                ARO
            
            
            1
            
            
            -Balance
                at end
                of year
            
            $
            25
            
            $
            194





**1** **2.**  **SHORT-TERM
      BORROWINGS:**





Short-term
      borrowings outstanding as of December 31, 2005, consisted of
      $65 million of borrowings from affiliates. In June 2005, the Company,
      FirstEnergy, OE, Penn, CEI, 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 4.0% and 2.0%,
      respectively.





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





**(A)**
            **NUCLEAR INSURANCE-******





The
      Price-Anderson
      Act limits the public liability relative to a single incident at a nuclear
      power
      plant to $10.8 billion. The amount is covered by a combination of private
      insurance and an industry retrospective rating plan. Based on its leasehold
      interest in Beaver Valley Unit 2, the Company’s maximum potential
      assessment under the industry retrospective rating plan (assuming the other
      affiliate co-owners contribute their proportionate shares of any assessments
      under the retrospective rating plan) would be $18.4 million per incident
      but not more than $2.8 million in any one year for each
      incident.





The
      Company is also
      insured as to its respective interest in Beaver Valley Unit 2 under
      policies issued to the operating company of the plant. Under these policies,
      up
      to $2.75 billion is provided for property damage and decontamination and
      decommissioning costs. The Company has also obtained approximately
      $74.3 million of insurance coverage for replacement power costs for its
      respective leasehold interest in Beaver Valley Unit 2. Under these
      policies, the Company can be assessed a maximum of approximately
      $4.1 million for incidents at any covered nuclear facility occurring during
      a policy year which are in excess of accumulated funds available to the insurer
      for paying losses.





The
      Company intends
      to maintain insurance against nuclear risks as described above as long as it
      is
      available. To the extent that replacement power, property damage,
      decontamination, decommissioning, repair and replacement costs and other such
      costs arising from a nuclear incident at any of the Company’s plants exceed the
      policy limits of the insurance in effect with respect to that plant, to the
      extent a nuclear incident is determined not to be covered by the Company’s
      insurance policies, or to the extent such insurance becomes unavailable in
      the
      future, the Company would remain at risk for such costs.


39


**(B)**
            **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
      $0.2 million have been accrued through December 31, 2005.





**(C)**
            **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, Inc. 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.





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, CEI 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. Excluding the Company's retained
      leasehold interests in Beaver Valley Unit 2 (18.26%). the transfer included
      the Company's prior owned interests in Beaver Valley Unit 2 (1.65%),
      Davis-Besse (48.62%) and Perry (19.91%).





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
      $1.7 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.





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.


41


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 the Company’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 Company 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 $22.9 million) between the purchase price specified in the
        Master
        Facility Lease and the net book value at the date of transfer was credited
        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 $101.0 million that is secured by a lien on the units
        purchased, bears interest at a rate per annum based on the weighted cost
        of TE’s
        long-term debt (4.38%) 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 TE’s outstanding pollution control debt. The timing of any refunding will be
        subject to market conditions and other factors.


On
      December 16,
      2005, the Company 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 $22.1 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 TE’s interest in associated decommissioning trust
      funds, other related assets and other liabilities associated with the
      transferred assets. In addition, TE received a promissory note from NGC in
      the
      principal amount of approximately $726.1 million, 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
      TE’s weighted average cost of long-term debt (4.38%), 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 to FES. The Company's 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. The Company will retain the generated KWH sales arrangement
      and the portion of expenses related to its retained leasehold interests in
      the
      Bruce Mansfield Plant and Beaver Valley Unit 2. 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
            
            $
            651Other
                property
                and investments
            
            
            287Current
                assets
            
            
            43Deferred
                charges
            
            
            2$
            983**Liabilities
                Related to Assets Transferred**Long-term
                debt
            
            $
            -Current
                liabilities
            
            
            -Noncurrent
                liabilities
            
            
            178$
            178**Net
                Assets Transferred**
            
            $
            805





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 :





**Three
                Months Ended**
            
            **March
                31,**
              **2005**
            
            **June
                30,**
              **2005**
            
            **September
                30,**
              **2005**
            
            **December
                31,**
              **2005*****(In
                millions)***Operating
                Revenues
            
            $
            241.8
            
            $
            259.1
            
            $
            286.9
            
            $
            252.4Operating
                Expenses and Taxes
            
            
            236.6
            
            
            251.9
            
            
            250.5
            
            
            226.7Operating
                Income
            
            
            5.2
            
            
            7.2
            
            
            36.4
            
            
            25.7Other
                Income
            
            
            2.7
            
            
            3.2
            
            
            12.3
            
            
            4.5Net
                Interest
                Charges
            
            
            7.5
            
            
            2.7
            
            
            6.5
            
            
            4.3Net
                Income
            
            $
            0.4
            
            $
            7.7
            
            $
            42.2
            
            $
            25.9Earnings
                (Loss) on Common Stock
            
            $
            (1.8
            )
            $
            5.5
            
            $
            40.5
            
            $
            24.2





**March
                31,**
            
            **June
                30,**
            
            **September
                30,**
            
            **December
                31,****Three
                Months Ended**
            
            **2004**
            
            **2004**
            
            **2004**
            
            **2004*****(In
                millions)***Operating
                Revenues
            
            $
            235.4
            
            $
            243.4
            
            $
            276.3
            
            $
            253.0Operating
                Expenses and Taxes
            
            
            224.9
            
            
            216.7
            
            
            251.4
            
            
            221.9Operating
                Income
            
            
            10.5
            
            
            26.7
            
            
            24.9
            
            
            31.1Other
                Income
            
            
            5.8
            
            
            4.7
            
            
            4.2
            
            
            8.3Net
                Interest
                Charges
            
            
            8.8
            
            
            9.8
            
            
            4.6
            
            
            6.6Net
                Income
            
            $
            7.5
            
            $
            21.6
            
            $
            24.5
            
            $
            32.8Earnings
                on
                Common Stock
            
            $
            5.3
            
            $
            19.4
            
            $
            22.2
            
            $
            30.5





45