**OHIO
      EDISON
      COMPANY**





**2005
      ANNUAL
      REPORT TO STOCKHOLDERS**










Ohio
      Edison Company
      is a wholly owned electric utility operating subsidiary of FirstEnergy Corp.
      Ohio Edison engages in the distribution and sale of electric energy to
      communities in an area of 7,500 square miles in central and northeastern Ohio
      and, through its wholly owned Pennsylvania Power Company subsidiary, 1,500
      square miles in western Pennsylvania. It also engages in the sale, purchase
      and
      interchange of electric energy with other electric companies. The areas Ohio
      Edison and Pennsylvania Power serve have populations of approximately 2.8
      million and 0.3 million, respectively.























**Contents**
            
            **Page**Glossary
                of
                Terms
            
            i-iiReport
                of
                Independent Registered Public Accounting Firm
            
            1Selected
                Financial Data
            
            2Management's
                Discussion and Analysis
            
            3-19Consolidated
                Statements of Income
            
            20Consolidated
                Balance Sheets
            
            21Consolidated
                Statements of Capitalization
            
            22-23Consolidated
                Statements of Common Stockholder's Equity
            
            24Consolidated
                Statements of Preferred Stock
            
            24Consolidated
                Statements of Cash Flows
            
            25Consolidated
                Statements of Taxes
            
            26Notes
                to
                Consolidated Financial Statements
            
            27-48











**GLOSSARY
      OF
      TERMS**





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





ATSI
            American
                Transmission Systems, Inc., owns and operates transmission
                facilitiesCEI
            The
                Cleveland
                Electric Illuminating Company, an affiliated Ohio electric
                utilityCompanies
            OE
                and
                PennFENOC
            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
                CompanyOhio
                Companies
            CEI,
                OE and
                TEPenelec
            Pennsylvania
                Electric Company, an affiliated Pennsylvania electric
                utilityPenn
            Pennsylvania
                Power Company, OE's wholly owned Pennsylvania electric utility
                subsidiaryPNBV
            PNBV
                Capital
                Trust, a special purpose entity created by OE in 1996TE
            The
                Toledo
                Edison Company, an affiliated Ohio electric utilityThe
                following
                abbreviations and acronyms are used to identify frequently used terms
                in
                this report:ALJ
            Administrative
                Law JudgeAOCL
            Accumulated
                Other Comprehensive LossAPB
            Accounting
                Principles BoardAPB
                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 ObligationCAL
            Confirmatory
                Action LetterCAT
            Commercial
                Activity TaxCO2
            Carbon
                DioxideCTC
            Competitive
                Transition ChargeDOJ
            United
                States
                Department of JusticeECAR
            East
                Central
                Area Reliability Coordination AgreementEITF
            Emerging
                Issues Task ForceEITF
                03-1
            EITF
                Issue No.
                03-1, "The Meaning of Other-Than-Temporary and Its Application to
                Certain
              Investments”EITF
                04-13
            EITF
                Issue No.
                04-13, "Accounting for Purchases and Sales of Inventory with the
                Same
                Counterparty"EPA
            Environmental
                Protection AgencyEPACT
            Energy
                Policy
                Act of 2005ERO
            Energy
                Reliability OrganizationFASB
            Financial
                Accounting Standards BoardFERC
            Federal
                Energy
                Regulatory CommissionFIN
            FASB
                InterpretationFIN
                46R
            FIN
                46
                (revised December 2003), "Consolidation of Variable Interest
                Entities"FIN
                47
            FIN
                47,
                “Accounting for Conditional Asset Retirement Obligations - an
                interpretation of FASB Statement No. 143”FMB
            First
                Mortgage
                BondsFSP
            FASB
                Staff
                PositionFSP
                106-1
            FASB
                Staff
                Position No.106-1, "Accounting and Disclosure Requirements Related
                to the
                Medicare
              Prescription
                Drug, Improvement and Modernization Act of 2003"FSP
                106-2
            FASB
                Staff
                Position No.106-2, "Accounting and Disclosure Requirements Related
                to
                the
              Medicare
                Prescription Drug, Improvement and Modernization Act of
                2003"FSP
                115-1 and
                FAS 124-1
            FASB
                Staff
                Position No. 115-1 and FAS 124-1, "The Meaning of Other-Than-Temporary
                Impairment and its Application to Certain Investments"GAAP
            Accounting
                Principles Generally Accepted in the United StatesGCAF
            Generation
                Charge Adjustment Factor





i


IRS
            Internal
                Revenue ServiceKWH
            Kilowatt-hoursLOC
            Letter
                of
                CreditMedicare
                Act
            Medicare
                Prescription Drug, Improvement and Modernization Act of
                2003MISO
            Midwest
                Independent System Transmission 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 CoalitionNOV
            Notices
                of
                ViolationNOX
            Nitrogen
                OxideNRC
            Nuclear
                Regulatory CommissionOCC
            Office
                of the
                Ohio Consumers' CounselOCI
            Other
                Comprehensive IncomeOPEB
            Other
                Post-Employment BenefitsPJM
            PJM
                Interconnection L.L.C.PLR
            Provider
                of
                Last ResortPPUC
            Pennsylvania
                Public Utility CommissionPUCO
            Public
                Utilities Commission of OhioPUHCA
            Public
                Utility
                Holding Company ActRCP
            Rate
                Certainty
                PlanRSP
            Rate
                Stabilization PlanRFP
            Request
              for
              ProposalRTC
            Regulatory
                Transition ChargeS&P
            Standard
&
                Poor’s Ratings ServiceSEC
            U.S.
                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
                143
            SFAS
                No. 143,
                "Accounting for Asset Retirement Obligations"SFAS
                144
            SFAS
                No. 144,
                "Accounting for the Impairment or Disposal of Long-Lived
                Assets"SFAS
                150
            SFAS
                No. 150,
                "Accounting for Certain Financial Instruments with Characteristics
                of Both
              Liabilities
                and Equity"SFAS
                151
            SFAS
                No. 151,
                "Inventory Costs - an amendment of ARB No. 43, Chapter
                4"SFAS
                153
            SFAS
                No. 153,
                "Exchanges of Nonmonetary Assets - an amendment of APB Opinion No.
                29"SFAS
                154
            SFAS
                No. 154,
                "Accounting Changes and Error Corrections - a replacement of APB
                Opinion
                No. 20 and FASB Statement No. 3"SO2
            Sulfur
                DioxideVIE
            Variable
                Interest Entity





ii


**Report
      of
      Independent Registered Public Accounting Firm**








To
      the Stockholder
      and Board of


Directors
      of Ohio
      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 Ohio Edison Company and its subsidiaries at December 31, 2005 and 2004,
      and the results of their operations and their cash flows for each of the three
      years in the period ended December 31, 2005 in conformity with accounting
      principles generally accepted in the United States of America. These financial
      statements are the responsibility of the Company’s management. Our
      responsibility is to express an opinion on these financial statements based
      on
      our audits. We conducted our audits of these statements in accordance with
      the
      standards of the Public Company Accounting Oversight Board (United States).
      Those standards require that we plan and perform the audit to obtain reasonable
      assurance about whether the financial statements are free of material
      misstatement. An audit includes examining, on a test basis, evidence supporting
      the amounts and disclosures in the financial statements, assessing the
      accounting principles used and significant estimates made by management, and
      evaluating the overall financial statement presentation. We believe that our
      audits provide a reasonable basis for our opinion.





As
      discussed in Note
      2(G) and Note 11 to the consolidated financial statements, the Company changed
      its method of accounting for asset retirement obligations as of January 1,
      2003 and conditional asset retirement obligations as of December 31, 2005 .








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.





**OHIO
                  EDISON COMPANY****SELECTED
                  FINANCIAL DATA****2005**
              
              **2004**
              
              **2003**
              
              **2002**
              
              **2001*****(Dollars
                  in thousands)*****GENERAL
                  FINANCIAL INFORMATION:**Operating
                  Revenues
              
              $
              2,975,553
              
              $
              2,945,583
              
              $
              2,925,310
              
              $
              2,948,675
              
              $
              3,056,464Operating
                  Income
              
              $
              335,383
              
              $
              335,529
              
              $
              336,936
              
              $
              453,831
              
              $
              466,819Income
                  Before
                  Cumulative Effectof
                  Accounting Changes
              
              $
              330,398
              
              $
              342,766
              
              $
              292,925
              
              $
              356,159
              
              $
              350,212Net
                  Income
              
              $
              314,055
              
              $
              342,766
              
              $
              324,645
              
              $
              356,159
              
              $
              350,212Earnings
                  on
                  Common Stock
              
              $
              311,420
              
              $
              340,264
              
              $
              321,913
              
              $
              349,649
              
              $
              339,510Total
                  Assets
              
              $
              6,097,277
              
              $
              6,482,627
              
              $
              7,316,489
              
              $
              7,789,539
              
              $
              7,915,391**CAPITALIZATION
                  AS OF DECEMBER 31:**Common
                  Stockholder’s Equity
              
              $
              2,502,191
              
              $
              2,493,809
              
              $
              2,582,970
              
              $
              2,839,255
              
              $
              2,671,001Preferred
                  Stock-Not
                  Subject to
                  Mandatory Redemption
              
              
              75,070
              
              
              100,070
              
              
              100,070
              
              
              100,070
              
              
              200,070Subject
                  to
                  Mandatory Redemption
              
              
              -
              
              
              -
              
              
              -
              
              
              13,500
              
              
              134,250Long-Term
                  Debt
                  and Other Long-Term Obligations
              
              
              1,019,642
              
              
              1,114,914
              
              
              1,179,789
              
              
              1,219,347
              
              
              1,614,996Total
                  Capitalization
              
              $
              3,596,903
              
              $
              3,708,793
              
              $
              3,862,829
              
              $
              4,172,172
              
              $
              4,620,317**CAPITALIZATION
                  RATIOS:**Common
                  Stockholder’s Equity
              
              
              69.6
              %
              
              67.2
              %
              
              66.9
              %
              
              68.1
              %
              
              57.8
              %Preferred
                  Stock-Not
                  Subject to
                  Mandatory Redemption
              
              
              2.1
              
              
              2.7
              
              
              2.6
              
              
              2.4
              
              
              4.3Subject
                  to
                  Mandatory Redemption
              
              
              -
              
              
              -
              
              
              -
              
              
              0.3
              
              
              2.9Long-Term
                  Debt
                  and Other Long-Term Obligations
              
              
              28.3
              
              
              30.1
              
              
              30.5
              
              
              29.2
              
              
              35.0Total
                  Capitalization
              
              
              100.0
              %
              
              100.0
              %
              
              100.0
              %
              
              100.0
              %
              
              100.0
              %**DISTRIBUTION
                  KWH DELIVERIES (Millions):**Residential
              
              
              10,901
              
              
              10,180
              
              
              10,009
              
              
              10,233
              
              
              9,646Commercial
              
              
              8,566
              
              
              8,276
              
              
              8,105
              
              
              7,994
              
              
              7,967Industrial
              
              
              11,058
              
              
              10,700
              
              
              10,658
              
              
              10,672
              
              
              10,995Other
              
              
              154
              
              
              144
              
              
              160
              
              
              154
              
              
              152Total
              
              
              30,679
              
              
              29,300
              
              
              28,932
              
              
              29,053
              
              
              28,760**CUSTOMERS
                  SERVED:**Residential
              
              
              1,062,665
              
              
              1,056,560
              
              
              1,044,419
              
              
              1,041,825
              
              
              1,033,414Commercial
              
              
              130,472
              
              
              129,017
              
              
              127,856
              
              
              119,771
              
              
              118,469Industrial
              
              
              1,152
              
              
              1,149
              
              
              1,182
              
              
              4,500
              
              
              4,573Other
              
              
              1,890
              
              
              1,751
              
              
              1,752
              
              
              1,756
              
              
              1,664Total
              
              
              1,196,179
              
              
              1,188,477
              
              
              1,175,209
              
              
              1,167,852
              
              
              1,158,120**Number
                  of Employees**
              
              
              1,422
              
              
              1,370
              
              
              1,521
              
              
              1,569
              
              
              1,618











2


**OHIO
      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, the Public Utilities
      Commission of Ohio and the Pennsylvania Public Utility Commission as disclosed
      in our Securities and Exchange Commission filings, generally, and with respect
      to heightened scrutiny at the Perry Nuclear Power Plant in particular, the
      continuing availability and operation of generating units, the ability of
      generating units to continue to operate at, or near full capacity, our inability
      to accomplish or realize anticipated benefits from strategic goals (including
      employee workforce factors), the anticipated benefits from our voluntary pension
      plan contributions, our ability to improve electric commodity margins and to
      experience growth in the distribution business, our ability to access the public
      securities and other capital markets and the cost of such capital, the outcome,
      cost and other effects of present and potential legal and administrative
      proceedings and claims related to the August 14, 2003 regional power
      outage, the risks and other factors discussed from time to time in our
      Securities and Exchange Commission filings, and other similar factors. Also,
      a
      credit rating should not be viewed as a recommendation to buy, sell or hold
      securities and may be revised or withdrawn by a rating agency at any time.
      We
      expressly disclaim any current intention to update any forward-looking
      statements contained herein as a result of new information, future events,
      or
      otherwise.*





**FirstEnergy
      Intra-System Generation Asset Transfers**




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





On
      October 24,
      2005, we completed the intra-system transfer of 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 an asset spin-off in the form of a
      dividend. FENOC continues to operate and maintain the nuclear generation
      assets.





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


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-generated assets
      arrangements with FES. Our expenses will be lower due to the nuclear fuel and
      operating costs assumed by NGC as well as depreciation and property tax expenses
      assumed by FGCO and NGC related to the transferred generating assets. OE will
      retain the nuclear-generated KWH sales arrangement and the portion of expenses
      related to our retained leasehold interests in Perry 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
      and
      eliminate the interest expense on certain pollution control notes to be
      transferred to FGCO and NGC. 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 in 2005 decreased to $311 million from $340 million in
      2004. Earnings on common stock in 2005 included an after-tax charge to income
      of
      $16 million from the cumulative effect of an accounting change due to the
      adoption of FIN 47 in December 2005 (see Note 2(G)). Income before the
      cumulative effect of an accounting change was $330 million in 2005. The
      earnings decrease in 2005 primarily resulted from increases in regulatory asset
      amortization and other operating costs and a decrease in other income, partially
      offset by higher operating revenues and lower purchased power and nuclear
      operating costs compared to 2004.





Earnings
      on
      common stock in 2004 increased to $340 million from $322 million in
      2003. Earnings on common stock in 2003 included an after-tax gain of
      $32 million from the cumulative effect of an accounting change due to the
      adoption of SFAS 143 (see Note 2(G)). Income before the cumulative
      effect of an accounting change was $293 million in 2003. The earnings
      increase in 2004 primarily resulted from lower nuclear operating costs and
      reduced financing costs, partially offset by higher purchased power costs
      compared to 2003.





*Operating
      Revenues*





Operating
      revenues
      increased by $30 million (1.0%) in 2005 compared with 2004 primarily due to
      increases of $50 million in retail generation and $43 million in
      distribution deliveries, partially offset by decreases of $37 million in
      wholesale sales revenue, $32 million in lease revenues from associated
      companies and an additional $6 million in shopping incentive credits
      discussed below. Increased retail generation revenues (residential -
      $20 million; commercial - $9 million; and industrial -
      $22 million) reflected the impact of higher KWH sales. The increased
      generation KWH sales to residential (7.0%) and commercial (4.5%) customers
      were
      due to warmer summer weather in 2005, compared to 2004, which increased
      air-conditioning loads. Increased industrial revenues were primarily due to
      higher unit prices and also reflected the impact of a 1.9% increase in
      generation KWH sales. Industrial sales were affected by increased shopping
      as
      generation services provided to industrial customers by alternative suppliers
      as
      a percent of total industrial sales delivered in our service area increased
      by
      1.0 percentage point. Commercial customer shopping decreased slightly by 0.6
      percentage point and residential customer shopping remained relatively unchanged
      compared to 2004.





The
      intra-system
      generation asset transfers discussed above had an effect on our wholesale sales
      revenues and lease revenues in the fourth quarter of 2005. Lower wholesale
      revenues in 2005 compared to 2004 reflected decreased sales to FES of
      $61 million (8.1% KWH sales decrease), due to reduced nuclear generation
      available for sale. In addition, the nuclear asset transfers on
      December 16, 2005 terminated our nuclear generation sales arrangement with
      FES (except for those revenues related to our retained nuclear leasehold
      interests). The decreased sales to FES were partially offset by a
      $24 million increase in sales to unaffiliated customers (including MSG
      sales) reflecting increased KWH sales (2.7%) and higher unit prices. Revenues
      from the leases of fossil generation assets to FGCO decreased when the lease
      arrangements were terminated as a result of the non-nuclear intra-system
      generation asset transfers completed on October 24, 2005.





Distribution
      revenues increased $43 million in 2005 compared with 2004 due to higher
      revenues in the residential sector ($44 million) and commercial sector
      ($2 million), partially offset by lower industrial revenues
      ($3 million). Higher distribution deliveries to residential and commercial
      customers due to warmer summer weather in 2005 were partially offset by lower
      unit prices. Revenues in the industrial sector decreased due to lower unit
      prices offsetting an increase in distribution deliveries.





Operating revenues increased by $20 million (0.7%) in 2004 compared with
      2003 primarily due to increases of $22 million in wholesale sales revenue
      and $12 million in retail generation revenues, partially offset by
      $16 million in shopping incentive credits discussed below. Revenues from
      wholesale sales to FES increased by $29 million, reflecting greater nuclear
      generation available for sale, and were partially offset by $10 million of
      lower revenues due to the expiration of a contract in July 2003. The higher
      retail generation revenues primarily resulted from a $9 million increase in
      sales to industrial customers, reflecting a 1.1 percentage point decrease in
      shopping by these customers in our service areas. Revenues from sales to
      residential customers decreased by $2 million as shopping within this
      sector increased by 2.5 percentage points. Commercial revenues increased by
      $5 million due to higher KWH sales and unit prices, while the percentage of
      commercial customers shopping remained relatively unchanged.


4


Revenues
      from
      distribution throughput increased $3 million in 2004 compared with 2003.
      Distribution deliveries to commercial customers increased by $11 million in
      2004 compared to 2003, reflecting increased KWH deliveries (2.1%) and higher
      unit prices. Lower unit prices offset the effect of higher throughput, resulting
      in a decrease of $9 million in revenues from industrial customers. The
      increased sales to the commercial and industrial sectors resulted from the
      improving economy in our service area.





Under
      our
      Ohio transition plan, we provided incentives to customers to encourage switching
      to alternative energy providers. In 2005 and 2004, we provided additional
      shopping credits of $6 million and $16 million, respectively, from 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 from
      the
      prior year are summarized in the following table:





**Changes
                in KWH Sales**
            
            **2005**
            
            **2004****Increase
                (Decrease)**Electric
                Generation:Retail
            
            
            4.4
            %
            
            0.5
            %Wholesale
            
            
            (5.2
            )%
            
            7.3
            %**Total
                Electric Generation Sales**
            
            
            (0.2
            )%
            
            3.7
            %Distribution
                Deliveries:Residential
            
            
            7.1
            %
            
            1.7
            %Commercial
            
            
            3.5
            %
            
            2.1
            %Industrial
            
            
            3.3
            %
            
            0.4
            %**Total
                Distribution Deliveries**
            
            
            4.7
            %
            
            1.3
            %





*Operating
      Expenses and Taxes*




Total
      operating expenses and taxes increased by $30 million in 2005 and by
      $22 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
            
            $
            (3
            )
            $
            4Purchased
                power costs
            
            
            (31
            )
            
            56Nuclear
                operating costs
            
            
            (38
            )
            
            (57
            )Other
                operating costs
            
            
            68
            
            
            (27
            )Provision
                for
                depreciation
            
            
            (14
            )
            
            5Amortization
                of regulatory assets
            
            
            46
            
            
            18Deferral
                of
                new regulatory assets
            
            
            (51
            )
            
            (27
            )General
                taxes
            
            
            13
            
            
            10Income
                taxes
            
            
            40
            
            
            40**Total
                operating expenses and taxes**
            
            **$**
            **30**
            
            **$**
            **22**




Lower
      fuel costs in
      2005, compared to 2004, resulted from decreased nuclear generation - down 4.5%.
      Purchased power costs decreased in 2005 due to lower unit costs offsetting
      an
      increase in KWH purchased to meet increased retail generation sales
      requirements. Lower nuclear operating costs in 2005 reflect the effect of lower
      owned/leased interests in the two plants (Beaver Valley Unit 2 - 55.62% and
      Perry - 35.24%) with refueling outages in 2005 as compared to Beaver Valley
      Unit 1 (100% owned) that had a refueling outage in 2004. In addition,
      nuclear operating costs incurred after the nuclear asset transfers were
      completed on December 16, 2005 were assumed by NGC. The increase in other
      operating costs in 2005 compared to 2004 was due to increased transmission
      expenses related to MISO Day 2 transactions that began on April 1,
      2005.





Higher
      fuel costs in
      2004 compared to 2003 resulted from increased nuclear generation - up 13.1%.
      Purchased power costs were higher in 2004 due to higher unit costs. Lower
      nuclear operating costs in 2004 were primarily the result of one scheduled
      refueling outage in 2004 compared to three scheduled refueling outages in 2003.
      The decrease in other operating costs in 2004 compared to 2003 was due to
      reduced labor costs and lower employee benefits expenses.


5


The
      decrease in
      depreciation expense in 2005 compared to 2004 was attributable to revised
      estimated service life assumptions for fossil generating plants and a decrease
      in the depreciation of leased electric plant as a result of the intra-system
      generation asset transfer. The provision for depreciation increased in 2004
      compared to 2003 primarily due to a slight change in the composite depreciation
      rate and a higher depreciable asset base. Increases in amortization of
      regulatory assets in 2005 and 2004 compared to the prior year resulted from
      higher amortization of Ohio transition regulatory assets. The higher deferrals
      of new regulatory assets in 2005 compared to 2004 primarily resulted from the
      PUCO-approved MISO cost deferrals and related interest ($49 million) (see
      Outlook - Regulatory Matters). The higher deferrals of new regulatory assets
      in
      2004 compared to 2003 primarily reflected higher shopping incentive deferrals
      ($16 million) and related interest ($10 million).





General
      taxes
      increased by $13 million in 2005 and by $10 million in 2004 compared
      to the prior year, primarily due to higher property taxes and the effect of
      higher KWH sales which increased Ohio KWH excise tax and Pennsylvania gross
      receipts tax. Property taxes increased in 2005 due to the absence of a
      $6 million Pennsylvania property tax refund recognized in 2004 and
      increased in 2004 due to a property tax settlement in 2003.





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” that 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
      law, except that the tax liability as computed will be multiplied by 4/5 in
      2005; 3/5 in 2006; 2/5 in 2007 and 1/5 in 2008, therefore eliminating the
      current income-based franchise tax over a five-year period. As a result of
      the
      new tax structure, all net deferred tax benefits that are not expected to
      reverse during the five-year phase-in period were written off as of
      June 30, 2005. The impact on income taxes associated with the required
      adjustment to net deferred taxes for 2005 was an additional tax expense of
      approximately $32 million, which was partially offset by the initial
      phase-out of the Ohio income-based franchise tax, which reduced income taxes
      by
      approximately $3 million in 2005.





*Other
      Income*





Other
      income
      decreased by $13 million in 2005 compared to 2004 due to a
      $8.5 million civil penalty payable to the DOJ and a $10 million
      liability for environmental projects recognized in connection with the
      W. H. Sammis Plant settlement (see Outlook - Environmental Matters),
      partially offset by higher interest income earned on associated company notes
      receivable. Other income increased $7 million in 2004 compared to 2003,
      primarily due to gains on disposition of property.





*Net
      Interest
      Charges*





Net
      interest charges
      continued to trend lower, decreasing by $1 million in 2005 and
      $44 million in 2004, compared to the prior year, due to our debt paydown
      program. Long-term debt interest was lower due to the redemption of $124 of
      pollution control notes in 2005. We also optionally redeemed $38 million of
      Penn’s preferred stock in 2005. We redeemed $165 million of long-term debt
      and remarketed $30 million of pollution control notes during
      2004.





*Cumulative
      Effect of Accounting Changes*





Results
      in 2005
      include an after-tax charge of $16 million recorded upon the adoption of
      FIN 47 in December 2005. We identified applicable legal obligations as
      defined under the new standard at our retired generating units, substation
      control rooms, service center buildings, line shops and office buildings,
      identifying asbestos as the primary conditional ARO. We recorded a conditional
      ARO liability of $27 million (including accumulated accretion for the
      period from the date the liability was incurred to the date of adoption), an
      asset retirement cost of $9 million(recorded as part of the carrying amount
      of the related long-lived asset), and accumulated depreciation of
      $9 million. W e
      charged regulatory
      liabilities for $1 million upon adoption of FIN 47 for the transition
      amounts related to establishing the ARO for asbestos removal from substation
      control rooms and service center buildings. The remaining cumulative effect
      adjustment for unrecognized depreciation and accretion of $26 million was
      charged to income ($16 million, net of tax) for the year ended
      December 31, 2005. (See Note 11.)





Upon
      adoption
      of SFAS 143 in the first quarter of 2003, we recorded an after-tax credit
      to net income of $32 million. The cumulative adjustment for unrecognized
      depreciation, 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 $54 million
      increase to income, or $32 million net of income taxes.


6


**Capital
      Resources and Liquidity**





Our
      cash
      requirements in 2005 for operating expenses, construction expenditures,
      scheduled debt maturities and preferred stock redemptions were met without
      increasing our net debt and preferred stock outstanding. During 2006, we expect
      to meet our contractual obligations with cash from operations. Borrowing
      capacity under credit facilities is available to manage working capital
      requirements. In connection
      with a
      plan to realign our capital structure, we plan to issue up to $600 million
      of
      new long-term debt in 2006. The proceeds are expected to be used as a return
      of
      equity capital to FirstEnergy.In subsequent years, we expect to use a
      combination of cash from operations and funds from the capital
      markets.





*Changes
      in Cash
      Position*





As
      of
      December 31, 2005, our cash and cash equivalents of approximately $1
      million remained unchanged from December 31, 2004.





*Cash
      Flows From
      Operating Activities*





Our
      net cash
      provided from operating activities during 2005, 2004 and 2003 are as follows:





**Operating
                Cash Flows**
            
            **2005**
            
            **2004**
            
            **2003*****(In
                millions)***Cash
                earnings(1)
            
            $
            755
            
            $
            776
            
            $
            689Pension
                trust
                contribution(2)
            
            
            (73
            )
            
            (44
            )
            
            --Working
                capital and other
            
            
            233
            
            
            (316
            )
            
            382Net
                cash
                provided from operating activities
            
            $
            915
            
            $
            416
            
            $
            1,071





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


(2)  Pension
      trust
      contributions in 2005 and 2004 are net of $34 million and $29 million
      of income tax benefits, respectively.





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)
            
            $
            314
            
            $
            343
            
            $
            325Non-Cash
                Charges (Credits):Provision
                for
                depreciation
            
            
            109
            
            
            122
            
            
            118Amortization
                of regulatory assets
            
            
            457
            
            
            411
            
            
            393Deferral
                of
                new regulatory assets
            
            
            (151
            )
            
            (101
            )
            
            (73
            )Nuclear
                fuel
                and lease amortization
            
            
            46
            
            
            43
            
            
            39Deferred
                income taxes and investment tax credits, net*
            
            
            (30
            )
            
            (73
            )
            
            (111
            )Cumulative
                effect of accounting changes
            
            
            16
            
            
            --
            
            
            (32
            )Other
                non-cash
                charges
            
            
            (6
            )
            
            31
            
            
            30Cash
                earnings
                (Non-GAAP)
            
            $
            755
            
            $
            776
            
            $
            689





*
      Excludes
      $29 million of deferred tax benefits from pension contributions in
      2004.





Net
      cash flows from
      operating activities increased $499 million in 2005 compared to 2004
      primarily due to a $549 million increase from changes in working capital
      and other, partially offset by a $29 million increase in after-tax
      voluntary pension trust contributions in 2005 compared to 2004 and a
      $21 million decrease in cash earnings for the reasons as described above
      under “Results from Operations”. The increase in working capital and other
      primarily reflects decreased outflows of $417 million from reduced tax payments
      and for accounts payable of $126 million plus $136 million of funds
      received in 2005 for pre-paid electric service (under a three-year Energy for
      Education Program with the Ohio Schools Council), partially offset by a decrease
      in cash provided from the settlement of accounts receivable of
      $124 million.





Net
      cash from
      operating activities decreased $655 million in 2004 compared to 2003 due to
      a $698 million decrease from changes in working capital and the
      $44 million after-tax voluntary pension trust contribution in 2004. These
      decreases were partially offset by an $87 million increase in cash earnings
      as described above under “Results from Operations.” The change in working
      capital primarily reflects decreases in accounts payable and accrued tax
      balances. In 2004 tax liabilities among affiliated companies were settled in
      accordance with the tax sharing agreement, reducing our accrued taxes by
      $249 million. Accrued taxes were also reduced by a $169 million
      federal income tax payment in 2004.


7


*Cash
      Flows From
      Financing Activities*




In
      2005, 2004 and
      2003, net cash used for financing activities of $728 million,
      $569 million and $982 million, respectively, primarily reflected the
      new issues and redemptions shown below:





**Securities
                Issued or Redeemed**
            
            **2005**
            
            **2004**
            
            **2003*****(In
                millions)******New
                Issues:***Pollution
                control notes
            
            $
            146
            
            $
            30
            
            $
            -Unsecured
                notes
            
            
            -
            
            
            -
            
            
            325Long-term
                revolving credit
            
            
            -
            
            
            -
            
            
            40$
            146
            
            $
            30
            
            $
            365***Redemptions:***FMB
            
            $
            81
            
            $
            63
            
            $
            410Pollution
                control notes
            
            
            271
            
            
            -
            
            
            30Secured
                notes
            
            
            56
            
            
            62
            
            
            62Preferred
                stock
            
            
            38
            
            
            1
            
            
            1Long-term
                revolving credit
            
            
            -
            
            
            40
            
            
            -Other,
                principally redemption premiums
            
            
            6
            
            
            6
            
            
            17$
            452
            
            $
            172
            
            $
            520Short-term
                borrowings, net
            
            $
            26
            
            $
            (4
            )
            $
            (225
            )





Net
      cash used for
      financing activities increased to $728 million in 2005 from
      $569 million in 2004. The increase resulted from a net increase of
      $134 million in debt refinancings as shown above and a $25 million
      increase of common stock dividends to FirstEnergy. The $413 million
      decrease in net cash used for financing activities in 2004 from 2003 resulted
      from a net reduction of $234 million in debt refinancings as shown above
      and a $178 million reduction in common stock dividends to FirstEnergy.





We
      had approximately
      $522 million of cash and temporary cash investments (which include
      short-term notes receivable from associated companies) and $201 million of
      short-term indebtedness as of December 31, 2005. We have authorization from
      the PUCO to incur short-term debt of up to $500 million, which is expected
      to come from the bank facilities and the utility money pool described below.
      Penn has authorization from the SEC, continued by FERC rules adopted as a result
      of EPACT's repeal of PUHCA, to incur short-term debt up to its charter limit
      of
      $44 million (as of December 31, 2005 and will have access to bank
      facilities and the utility money pool).





OES
      Capital is a
      wholly owned subsidiary of OE whose borrowings are secured by customer accounts
      receivable purchased from OE. OES Capital can borrow up to $170 million
      ($30 million unused as of December 31, 2005) under a receivables
      financing arrangement. As a separate legal entity with separate creditors,
      OES
      Capital would have to satisfy its obligations to creditors before any of its
      remaining assets could be made available to OE.





Penn
      Power Funding
      LLC (Penn Funding), a wholly owned subsidiary of Penn, is a limited liability
      company whose borrowings are secured by customer accounts receivable purchased
      from Penn. Penn Funding can borrow up to the full amount of $25 million
      available as of December 31, 2005 under a receivables financing
      arrangement. As a separate legal entity with separate creditors, Penn Funding
      would have to satisfy its obligations to creditors before any of its remaining
      assets could be made available to Penn. On July 15,
      2005, the facility was renewed until June 29, 2006.





As
      of
      December 31, 2005, we had the aggregate capability to issue approximately
      $ 429 million of
      additional FMB on the basis of property additions and retired bonds under the
      terms of our mortgage indentures. Our issuance of FMB is also subject to
      provisions of our senior note indentures generally limiting the incurrence
      of
      additional secured debt, subject to certain exceptions that would permit, among
      other things, the issuance of secured debt (including FMB) (i) supporting
      pollution control notes or similar obligations, or (ii) as an extension, renewal
      or replacement of previously outstanding secured debt. In addition, these
      provisions would permit us to incur additional secured debt not otherwise
      permitted by a specified exception of up to $ 651 million
      as of
      December 31, 2005. Based upon applicable earnings coverage tests in our
      charters, we could issue a total of $ 3.1 billion
      of preferred
      stock (assuming no additional debt was issued) as of December 31,
      2005.





On
      June 14,
      2005, we, FirstEnergy, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as
      Borrowers, entered into a syndicated $2 billion five-year revolving credit
      facility with a syndicate of banks that expires in June 2010. Borrowings under
      the facility are available to each Borrower separately and mature on the earlier
      of 364 days from the date of borrowing or the commitment expiration date, as
      the
      same may be extended. Our borrowing limit under the facility is
      $500 million and Penn's is $50 million, subject in each case to applicable
      regulatory approvals.


8


Under
      the revolving
      credit facility, borrowers may request the issuance of letters of credit
      expiring up to one year from the date of issuance. The stated amount of
      outstanding letters of credit will count against total commitments available
      under the facility and against the applicable borrower’s borrowing sub-limit.
      Total unused borrowing capability under existing credit facilities and accounts
      receivable financing facilities totaled $605 million as of
      December 31, 2005.





The
      revolving credit
      facility contains financial covenants requiring each borrower to maintain a
      consolidated debt to total capitalization ratio of no more than 65%. As of
      December 31, 2005, debt to total capitalization as defined under the
      revolving credit facility was 38% for OE and 42% for Penn.





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 influenced by the ratings of our
      securities. The following table displays FirstEnergy’s and the OE Companies’
securities ratings as of December 31, 2005. The ratings outlook from
      S&P on all securities is stable. The ratings outlook from Moody's &
Fitch on all securities is positive.





**Ratings
                of Securities**
            
            **Securities**
            
            **S&P**
            
            **Moody’s**
            
            **Fitch****FirstEnergy**
            
            
            Senior
                unsecured
            
            
            BBB-
            
            
            Baa3
            
            
            BBB-**Ohio
                Edison**
            
            
            Senior
                unsecured
            
            
            BBB-
            
            
            Baa2
            
            
            BBBPreferred
                stock
            
            
            BB+
            
            
            Ba1
            
            
            BBB-**Penn**
            
            
            Senior
                secured
            
            
            BBB+
            
            
            Baa1
            
            
            BBB+Senior
                unsecured(1)
            
            
            BBB-
            
            
            Baa2
            
            
            BBBPreferred
                stock
            
            
            BB+
            
            
            Ba1
            
            
            BBB-





(1)
            Penn's
                only
                senior unsecured debt obligations are notes underlying pollution
                control
                revenue refunding bonds issued by the Ohio Air Quality Development
                Authority to which bonds this rating
                applies.





*Cash
      Flows From
      Investing Activities*




Net
      cash used
      for investing activities totaled $188 million in 2005 compared to
      $152 million provided from investing activities in 2004. The
      $262 million change resulted primarily from the absence in 2005 of
      $278 million of cash proceeds from certificates of deposit in 2004, loan
      repayments made to associated companies and $78 million of investments for
      an escrow fund and a mortgage indenture deposit, partially offset by a
      $193 million increase in principal payments received on long-term notes
      receivable from associated companies. Net cash provided from investing
      activities increased by $260 million in 2004 from 2003. The change resulted
      primarily from the $278 million of certificates of deposit cash proceeds in
      2004, a $62 million increase in loan repayments from associated companies
      and collection of principal on long-term notes receivable. These increases
      were
      partially offset by a $46 million increase in property
      additions.





Our
      capital spending
      for the period 2006-2010 is expected to be about $635 million, of which
      approximately $119 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 asset transfers.


9


**Contractual
      Obligations**





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





**2007-**
            
            **2009-****Contractual
                Obligations**
            
            **Total**
            
            **2006**
            
            **2008**
            
            **2010**
            
            **Thereafter*****(In
                millions)***Long-term
                debt(1)
            
            $
            1,306
            
            $
            3
            
            $
            185
            
            $
            4
            
            $
            
            
            
            1,114Short-term
                borrowings
            
            
            201
            
            
            201
            
            
            -
            
            
            -
            
            
            
            
            
            -Capital
                leases
            
            
            7
            
            
            5
            
            
            1
            
            
            -
            
            
            
            
            
            1Operating
                leases(2)
            
            
            1,120
            
            
            86
            
            
            194
            
            
            204
            
            
            
            
            
            636Purchases(3)
            
            
            36
            
            
            14
            
            
            12
            
            
            9
            
            
            
            
            
            1Total
            
            $
            2,670
            
            $
            309
            
            $
            392
            
            $
            217
            
            $
            
            
            
            1,752





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


(2)
            Operating
                lease payments are net of capital trust receipts of $475.8 million
                (see Note 6).


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





**Off-Balance
      Sheet Arrangements**





We
      have obligations
      that are not included on our Consolidated Balance Sheets related to the sale
      and
      leaseback arrangements involving Perr y
      Unit 1 and
      Beaver Valley Unit 2, which are satisfied through operating lease payments
      (see Note 6). The present value of these operating lease commitments, net
      of trust investments, was $652 million as of December 31,
      2005.





**Interest
      Rate Risk**





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





**Comparison
                of Carrying Value to Fair Value****There-**
            
            
            
            **Fair****Year
                of Maturity**
            
            **2006**
            
            **2007**
            
            **2008**
            
            **2009**
            
            **2010**
            
            **after**
            
            **Total**
            
            **Value*****(Dollars
                in millions)***AssetsInvestments
                Other Than Cashand
                Cash
                Equivalents-Fixed
                Income
            
            $
            
            
            
            36
            
            $
            39
            
            $
            17
            
            $
            25
            
            $
            29
            
            $
            1,977
            
            **$**
            2,123
            
            **$**
            1,873Average
                interest rate
            
            
            
            
            
            8.1
            %
            
            8.2
            %
            
            8.2
            %
            
            8.5
            %
            
            8.6
            %
            
            5.0
            %
            
            5.3
            %Liabilities
              Long-term
                Debt
                and OtherLong-Term
                Obligations:Fixed
                rate
            
            $
            
            
            
            3
            
            $
            6
            
            $
            179
            
            $
            2
            
            $
            65
            
            $
            318
            
            **$**
            573
            
            **$**
            576Average
                interest rate
            
            
            
            
            
            8.3
            %
            
            7.9
            %
            
            4.1
            %
            
            8.0
            %
            
            5.5
            %
            
            6.0
            %
            
            5.4
            %Variable
                rate
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            $
            733
            
            **$**
            733
            
            **$**
            733Average
                interest rate
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            3.3
            %
            
            3.3
            %Short-term
                Borrowings
            
            $
            
            
            
            201
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            **$**
            201
            
            **$**
            201Average
                interest rate
            
            
            
            
            
            4.2
            %
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            4.2
            %





**Equity
      Price
      Risk**




Included
      in our
      nuclear decommissioning trust investments are marketable equity securities
      carried at their market value of approximately
      $67 million and $248 million as of December 31, 2005 and 2004,
      respectively. A hypothetical 10% decrease in prices quoted by stock exchanges
      would result in a $7 million reduction in fair value as of
      December 31, 2005. As discussed in Note 5 - 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 nuclear generation
      assets.


10


**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. In Ohio and Pennsylvania, 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, the PPUC and the FERC for
      recovery from customers in the future periods or for which authorization is
      probable. Without the probability of such authorization, costs currently
      recorded as regulatory assets would have been charged to income as incurred.
      All
      regulatory assets are expected to be recovered under the provisions of our
      transition plan and rate restructuring plan. Our regulatory assets were
      $0.8 billion and $1.1 billion as of December 31, 2005 and 2004,
      respectively. Penn had net regulatory liabilities of $59 million and
      $19 million as of December 31, 2005 and 2004, respectively, which are
      included in Other Noncurrent Liabilities on the Consolidated Balance Sheets
      as
      of December 31, 2005 and 2004.





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
                  $75 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**2006
            
            $
            1692007
            
            
            1762008
            
            
            198**Total
                Amortization**
            
            **$**
            **543**





11


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 Ohio Companies filed a Motion for Clarification of
      the PUCO order approving the RCP. The Ohio Companies sought clarity on issues
      related to distribution deferrals, including requirements of the review process,
      timing for recognizing certain deferrals and definitions of the types of
      qualified expenditures. The Ohio Companies also sought confirmation that the
      list of deferrable distribution expenditures originally included in the revised
      stipulation fall within the PUCO order definition of qualified expenditures.
      On
      January 25, 2006, the PUCO issued an Entry on Rehearing granting in part,
      and denying in part, the Ohio Companies’ previous requests and clarifying issues
      referred to above. The PUCO granted the Ohio Companies’ requests to: 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 Ohio Companies’ methodology for determining distribution deferral
      amounts, but denied the Motion in that the PUCO Staff must verify the level
      of
      distribution expenditures contained in current rates, as opposed to simply
      accepting the amounts contained in the Companies’ Motion. On February 3,
      2006, several other parties filed applications for rehearing on the PUCO's
      January 4, 2006 Order. The Ohio Companies responded to the 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 $34 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.





On
      October 11,
      2005, Penn filed a plan with the PPUC to secure electricity supply for its
      customers at set rates following the end of its transition period on
      December 31, 2006. Penn is recommending that an RFP process cover the
      period January 1, 2007 through May 31, 2008. Hearings were held on
      January 10, 2006 with main briefs filed on January 27, 2006 and reply
      briefs on February 3, 2006. On February
      17,
      2006, theALJ
      issued a
      Recommended Decision to adopt Penn's RFP process with modifications. A PPUC
      vote
      is expected in April 2006. Under Pennsylvania's electric competition law, we
      are
      required to secure generation supply for customers who do not choose alternative
      suppliers for their electricity.





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.


12


In
      May 2004, the
      PPUC issued an order approving revised reliability benchmarks and standards,
      including revised benchmarks and standards for Met-Ed, Penelec and Penn. Met-Ed,
      Penelec and Penn filed a Petition for Amendment of Benchmarks with the PPUC
      on
      May 26, 2004, due to their implementation of automated outage management
      systems following restructuring. On December 30, 2005, the ALJ recommended
      that
      the PPUC adopt the Joint Petition for Settlement among the parties involved
      in
      the three Companies’ request to amend the distribution reliability benchmarks,
      thereby eliminating the need for full litigation. The ALJ’s recommendation,
      adopting the revised benchmarks and standards was approved by the PPUC on
      February 9, 2006.





The
      EPACT provides
      for the creation of an ERO to establish and enforce reliability standards for
      the bulk power system, subject to FERC review. On February 3, 2006, the FERC
      adopted a rule establishing certification requirements for the ERO, as well
      as
      regional entities envisioned to assume monitoring responsibility for the new
      reliability standards.





The
      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 and Pennsylvania and a detailed
      discussion of reliability initiatives, including initiatives by the PPUC, that
      impact Penn.


13


*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 our website at www.firstenergycorp.com/environmental .





*W.
      H. Sammis
      Plant-*





In
      1999 and 2000,
      the EPA issued NOV or Compliance Orders to nine utilities alleging violations
      of
      the Clean Air Act based on operation and maintenance of 44 power plants,
      including the W. H. Sammis Plant, which was owned at that time by OE and Penn.
      In addition, the DOJ filed eight civil complaints against various investor-owned
      utilities, including a complaint against OE and Penn in the U.S. District Court
      for the Southern District of Ohio. These cases are referred to as New Source
      Review cases. On March 18, 2005, OE and Penn announced that they had
      reached a settlement with the EPA, the DOJ and three states (Connecticut, New
      Jersey, and New York) that resolved all issues related to the W. H. Sammis
      Plant
      New Source Review litigation. This
      settlement
      agreement was approved by the Court on July 11, 2005, and requires
      reductions of NO x and SO 2 emissions at the
      W. H. Sammis Plant and other coal fired plants through the installation of
      pollution control devices and provides for stipulated penalties for failure
      to
      install and operate such pollution controls in accordance with that
      agreement. Consequently, if we
      fail to install such pollution control devices, for any reason, including,
      but
      not limited to, the failure of any third-party contractor to timely meet its
      delivery obligations for such devices, we could be exposed to penalties under
      the settlement agreement. Capital expenditures necessary to meet those
      requirements are currently estimated to be $1.5 billion (the primary
      portion of which is expected to be spent in the 2008 to 2011 time period).
      On
      August 26, 2005, FGCO entered into an agreement with Bechtel Power
      Corporation (Bechtel), under which Bechtel will engineer, procure, and construct
      air quality control systems for the reduction of sulfur dioxide emissions.
      The
      settlement agreement also requires OE and Penn to spend up to $25 million
      toward environmentally beneficial projects, which include wind energy purchased
      power agreements over a 20-year term. OE and Penn agreed to pay a civil penalty
      of $8.5 million. Results in 2005 included the penalties payable by OE and
      Penn of $7.8 million and $0.7 million, respectively. OE and Penn also
      recognized liabilities of $9.2 million and $0.8 million,  respectively,
      for
      probable future cash contributions toward environmentally beneficial
      projects.





*Other
      Legal
      Proceedings*





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





*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.


14


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





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





*Nuclear
      Plant
      Matters-*





As
      of
      December 16, 2005 NGC acquired ownership of the nuclear generation assets
      transferred from the OE, Penn, CEI and TE with the exception of leasehold
      interests of OE and TE in certain of the nuclear plants that are subject to
      sale
      and leaseback arrangements with non-affiliates. Excluding our retained leasehold
      interests in Beaver Valley Unit 2 (21.66%) and Perry (12.58%), the transfer
      included our prior owned interests in Beaver Valley Unit 1 (100%), Beaver
      Valley Unit 2 (33.96%) and Perry (22.66%).




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


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




On
        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-*





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.







15






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




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




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





See
      Note 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.





16




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
      returns 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 $107 million). As a result of our voluntary
      contribution and the increased market value of pension plan assets, we
      recognized a prepaid benefit cost of $225 million as of December 31,
      2005. As prescribed by SFAS 87, we eliminated our additional minimum
      liability of $152 million and our intangible asset of $33 million. In
      addition, the entire AOCL balance was credited by $69 million (net of
      $49 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 its health care plans, and projections of future medical trend
      rates. The effect on OE'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
              %
              $
              1.4
              
              $
              0.8
              
              $
              2.2Long-term
                  return on assets
              
              
              Decrease
                  by 0.25
              %
              $
              1.7
              
              $
              -
              
              $
              1.7Health
                  care
                  trend rate
              
              
              Increase
                  by 1
              %
              
              na
              
              $
              5.2
              
              $
              5.2




*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).





17




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.
  *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 Issue 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.





*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.


18




*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 by us beginning January 1, 2006. We
      do not expect it to have a material impact on our financial
      statements.





19


**OHIO
                  EDISON COMPANY****CONSOLIDATED
                  STATEMENTS OF INCOME****For
                  the Years Ended December 31,**
              
              **2005**
              
              **2004**
              
              **2003*****(In
                  thousands)*****OPERATING
                  REVENUES (Note 2(I))**
              
              $
              2,975,553
              
              $
              2,945,583
              
              $
              2,925,310**OPERATING
                  EXPENSES AND TAXES:**Fuel
              
              
              53,113
              
              
              56,560
              
              
              52,169Purchased
                  power (Note 2(I))
              
              
              939,193
              
              
              970,670
              
              
              914,723Nuclear
                  operating costs
              
              
              337,901
              
              
              375,309
              
              
              432,315Other
                  operating costs (Note 2(I))
              
              
              404,763
              
              
              336,772
              
              
              363,989Provision
                  for
                  depreciation
              
              
              108,583
              
              
              122,413
              
              
              117,895Amortization
                  of regulatory assets
              
              
              457,205
              
              
              411,326
              
              
              393,409Deferral
                  of
                  new regulatory assets
              
              
              (151,032
              )
              
              (100,633
              )
              
              (73,183
              )General
                  taxes
              
              
              193,284
              
              
              180,523
              
              
              170,078Income
                  taxes
              
              
              297,160
              
              
              257,114
              
              
              216,979Total
                  operating expenses and taxes
              
              
              2,640,170
              
              
              2,610,054
              
              
              2,588,374**OPERATING
                  INCOME**
              
              
              335,383
              
              
              335,529
              
              
              336,936**OTHER
                  INCOME (net of income taxes) (Notes 2(I))**
              
              
              61,243
              
              
              74,077
              
              
              66,782**NET
                  INTEREST CHARGES:**Interest
                  on
                  long-term debt
              
              
              58,709
              
              
              59,465
              
              
              91,068Allowance
                  for
                  borrowed funds used duringconstruction
                  and capitalized interest
              
              
              (10,849
              )
              
              (7,211
              )
              
              (6,075
              )Other
                  interest
                  expense
              
              
              16,679
              
              
              12,026
              
              
              22,340Subsidiary's
                  preferred stock dividend requirements
              
              
              1,689
              
              
              2,560
              
              
              3,460Net
                  interest
                  charges
              
              
              66,228
              
              
              66,840
              
              
              110,793**INCOME
                  BEFORE CUMULATIVE EFFECT****OF
                  ACCOUNTING CHANGES**
              
              
              330,398
              
              
              342,766
              
              
              292,925Cumulative
                  effect of accounting changes (net of income taxes
                  (benefit)of
                  ($9,223,000) and $22,389,000, respectively) (Note 2(G))
              
              
              (16,343
              )
              
              -
              
              
              31,720**NET
                  INCOME**
              
              
              314,055
              
              
              342,766
              
              
              324,645**PREFERRED
                  STOCK DIVIDEND REQUIREMENTS**
              
              
              2,635
              
              
              2,502
              
              
              2,732**EARNINGS
                  ON COMMON STOCK**
              
              $
              311,420
              
              $
              340,264
              
              $
              321,913The
                  accompanying Notes to Consolidated Financial Statements are an
                  integral
                  part of these statements.
   20
  **OHIO
                    EDISON COMPANY****CONSOLIDATED
                    BALANCE SHEETS****As
                    of
                    December 31,**
                
                **2005**
                
                **2004*****(In
                    thousands)*****ASSETS****UTILITY
                    PLANT:**In
                    service
                
                $
                2,526,851
                
                $
                5,440,374Less
                    -
                    Accumulated provision for depreciation
                
                
                984,463
                
                
                2,716,8511,542,388
                
                
                2,723,523Construction
                    work in progress -Electric
                    plant
                
                
                58,785
                
                
                203,167Nuclear
                    fuel
                
                
                -
                
                
                21,69458,785
                
                
                224,8611,601,173
                
                
                2,948,384**OTHER
                    PROPERTY AND INVESTMENTS:**Investment
                    in
                    lease obligation bonds (Note 6)
                
                
                325,729
                
                
                354,707Nuclear
                    plant
                    decommissioning trusts
                
                
                103,854
                
                
                436,134Long-term
                    notes receivable from associated companies
                
                
                1,774,643
                
                
                208,170Other
                
                
                44,210
                
                
                48,5792,248,436
                
                
                1,047,590**CURRENT
                    ASSETS:**Cash
                    and cash
                    equivalents
                
                
                929
                
                
                1,230Receivables-Customers
                    (less accumulated provision of $7,619,000 and $6,302,000,respectively, for uncollectible accounts)
                
                
                290,887
                
                
                274,304Associated
                    companies
                
                
                187,072
                
                
                245,148Other
                    (less
                    accumulated provisions of $4,000 and $64,000, respectively,for
                    uncollectible accounts)
                
                
                15,327
                
                
                18,385Notes
                    receivable from associated companies
                
                
                520,762
                
                
                538,871Materials
                    and
                    supplies, at average cost
                
                
                -
                
                
                90,072Prepayments
                    and other
                
                
                93,129
                
                
                13,1041,108,106
                
                
                1,181,114**DEFERRED
                    CHARGES:**Regulatory
                    assets
                
                
                774,983
                
                
                1,115,603Prepaid
                    pension costs
                
                
                224,813
                
                
                -Property
                    taxes
                
                
                52,875
                
                
                61,419Unamortized
                    sale and leaseback costs
                
                
                55,139
                
                
                60,242Other
                
                
                31,752
                
                
                68,2751,139,562
                
                
                1,305,539$
                6,097,277
                
                $
                6,482,627**CAPITALIZATION
                    AND LIABILITIES****CAPITALIZATION
                    (See Consolidated Statements of Capitalization):**Common
                    stockholder's equity
                
                $
                2,502,191
                
                $
                2,493,809Preferred
                    stock not subject to mandatory redemption
                
                
                60,965
                
                
                60,965Preferred
                    stock of consolidated subsidiary not subject to mandatory
                    redemption
                
                
                14,105
                
                
                39,105Long-term
                    debt
                    and other long-term obligations
                
                
                1,019,642
                
                
                1,114,9143,596,903
                
                
                3,708,793**CURRENT
                    LIABILITIES:**Currently
                    payable long-term debt
                
                
                280,255
                
                
                398,263Short-term
                    borrowings-Associated
                    companies
                
                
                57,715
                
                
                11,852Other
                
                
                143,585
                
                
                167,007Accounts
                    payable-Associated
                    companies
                
                
                172,511
                
                
                187,921Other
                
                
                9,607
                
                
                10,582Accrued
                    taxes
                
                
                163,870
                
                
                153,400Accrued
                    interest
                
                
                8,333
                
                
                11,992Other
                
                
                61,726
                
                
                62,671897,602
                
                
                1,003,688**NONCURRENT
                    LIABILITIES:**Accumulated
                    deferred income taxes
                
                
                769,031
                
                
                766,276Accumulated
                    deferred investment tax credits
                
                
                24,081
                
                
                62,471Asset
                    retirement obligation
                
                
                82,527
                
                
                339,134Retirement
                    benefits
                
                
                291,051
                
                
                307,880Deferred
                    revenues - electric service programs
                
                
                121,693
                
                
                -Other
                
                
                314,389
                
                
                294,3851,602,772
                
                
                1,770,146**COMMITMENTS
                    AND CONTINGENCIES (Notes 6 and 13)**$
                6,097,277
                
                $
                6,482,627The
                    accompanying Notes to Consolidated Financial Statements are an
                    integral
                    part of these balance sheets.
   21
  **OHIO
                    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,
                    without par value, authorized 175,000,000 shares-100 shares
                    outstanding
                
                
                
                
                
                
                
                
                
                $
                2,297,253
                
                $
                2,098,729Accumulated
                    other comprehensive income (loss) (Note 2(F))
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                4,094
                
                
                (47,118
                )Retained
                    earnings (Note 10(A))
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                200,844
                
                
                442,198Total
                    common
                    stockholder's equity
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                2,502,191
                
                
                2,493,809**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
                    6,000,000 shares3.90%
                
                
                152,510
                
                
                152,510
                
                
                
                
                $
                103.63
                
                $
                15,804
                
                
                15,251
                
                
                15,2514.40%
                
                
                176,280
                
                
                176,280
                
                
                
                
                
                108.00
                
                
                19,038
                
                
                17,628
                
                
                17,6284.44%
                
                
                136,560
                
                
                136,560
                
                
                
                
                
                103.50
                
                
                14,134
                
                
                13,656
                
                
                13,6564.56%
                
                
                144,300
                
                
                144,300
                
                
                
                
                
                103.38
                
                
                14,917
                
                
                14,430
                
                
                14,430Total
                
                
                609,650
                
                
                609,650
                
                
                
                
                
                
                
                
                63,893
                
                
                60,965
                
                
                60,965**PREFERRED
                    STOCK OF CONSOLIDATED****SUBSIDIARY
                    NOT SUBJECT TO MANDATORY****REDEMPTION
                    (Note 10(B)):****Pennsylvania
                    Power Company-**Cumulative,
                    $100 par value-Authorized
                    1,200,000 shares4.24%
                
                
                40,000
                
                
                40,000
                
                
                
                
                
                103.13
                
                
                4,125
                
                
                4,000
                
                
                4,0004.25%
                
                
                41,049
                
                
                41,049
                
                
                
                
                
                105.00
                
                
                4,310
                
                
                4,105
                
                
                4,1054.64%
                
                
                60,000
                
                
                60,000
                
                
                
                
                
                102.98
                
                
                6,179
                
                
                6,000
                
                
                6,0007.75%
                
                
                -
                
                
                250,000
                
                
                
                
                
                
                
                
                -
                
                
                -
                
                
                25,000Total
                
                
                141,049
                
                
                391,049
                
                
                
                
                
                
                
                
                14,614
                
                
                14,105
                
                
                39,105
   22
  **OHIO
                    EDISON COMPANY****CONSOLIDATED
                    STATEMENTS OF CAPITALIZATION (Cont'd)****As
                    of
                    December 31,**
                
                **2005**
                
                **2004**
                
                
                
                
                
                **2005**
                
                **2004**
                
                **2005**
                
                **2004*****(in
                    thousands)*****LONG-TERM
                    DEBT AND OTHER****LONG-TERM
                    OBLIGATIONS (Note 10(C)):****First
                    mortgage bonds:****Ohio Edison Company-**
                
                
                
                
                **Pennsylvania
                    Power Company-**6.875%
                    due
                    2005
                
                
                -
                
                
                80,000
                
                9.740%
                    due 2005-2019
                
                13,669
                
                
                14,6437.625%
                    due
                    2023
                
                6,500
                
                
                6,500Total
                    first
                    mortgage bonds
                
                
                -
                
                
                80,000
                
                
                
                
                
                
                
                
                20,169
                
                
                21,143
                
                
                20,169
                
                
                101,143**Secured
                    notes:****Ohio
                    Edison Company-**
                
                
                
                
                
                
                **Pennsylvania
                    Power Company-**7.680%
                    due
                    2005
                
                
                -
                
                
                51,461
                
                
                5.400%
                    due 2013
                
                
                1,000
                
                
                1,000* 
3.050%
                    due 2015
                
                
                19,000
                
                
                19,000
                
                
                5.400%
                    due 2017
                
                
                10,600
                
                
                10,6006.750%
                    due
                    2015
                
                
                -
                
                
                40,000
                
                *3.300%
                    due 2017
                
                
                17,925
                
                
                17,925* 
3.250%
                    due 2015
                
                
                50,000
                
                
                50,000
                
                
                5.900%
                    due 2018
                
                
                16,800
                
                
                16,800* 
3.200%
                    due 2016
                
                
                47,725
                
                
                47,725
                
                
                *3.300%
                    due 2021
                
                10,525
                
                
                14,4827.050%
                    due
                    2020
                
                
                60,000
                
                
                60,000
                
                
                6.150%
                    due 2023
                
                
                12,700
                
                
                12,700* 
1.700%
                    due 2021
                
                
                -
                
                
                443
                
                
                *3.610%
                    due 2027
                
                
                10,300
                
                
                10,3005.375%
                    due
                    2028
                
                
                13,522
                
                
                13,522
                
                
                5.375%
                    due 2028
                
                
                1,734
                
                
                1,7345.625%
                    due
                    2029
                
                
                -
                
                
                50,000
                
                
                5.450%
                    due 2028
                
                
                6,950
                
                
                6,9505.950%
                    due
                    2029
                
                
                -
                
                
                56,212
                
                
                6.000%
                    due 2028
                
                
                14,250
                
                
                14,250* 
3.050%
                    due 2029
                
                
                100,000
                
                
                -
                
                
                5.950%
                    due 2029
                
                
                -
                
                
                238* 
3.100%
                    due 2029
                
                
                6,450
                
                
                -
                
                
                1.800%
                    due 2033
                
                
                -
                
                
                5,200* 
3.050%
                    due 2030
                
                
                60,400
                
                
                60,400* 
3.350%
                    due 2031
                
                
                69,500
                
                
                69,500* 
1.800%
                    due 2033
                
                
                -
                
                
                44,800* 
3.100%
                    due 2033
                
                
                12,300
                
                
                12,3005.450%
                    due
                    2033
                
                
                14,800
                
                
                14,800* 
3.350%
                    due 2033
                
                
                50,000
                
                
                50,000* 
3.100%
                    due 2033
                
                
                108,000
                
                
                108,000Limited
                    Partnerships-7.32%
                    weighted
                    averageinterest rate due 2005-2010
                
                
                12,859
                
                
                17,272Total
                    secured
                    notes
                
                
                624,556
                
                
                765,435
                
                
                
                
                
                
                
                
                102,784
                
                
                112,179
                
                
                727,340
                
                
                877,614**Unsecured
                    notes:****Ohio
                    Edison Company-**
                
                
                
                
                
                
                **Pennsylvania
                    Power Company-**4.000%
                    due
                    2008
                
                
                175,000
                
                
                175,000
                
                
                *3.500%
                    due 2029
                
                
                14,500
                
                
                14,500* 
3.550%
                    due 2014
                
                
                50,000
                
                
                50,000
                
                
                5.390%
                    due 2010
                  to associated
                  company5.450%
                    due
                    2015
                
                
                150,000
                
                
                150,000
                
                
                
                
                
                
                
                
                62,900
                
                
                -* 
3.850%
                    due 2018
                
                
                33,000
                
                
                33,000* 
3.850%
                    due 2018
                
                
                23,000
                
                
                23,000* 
3.750%
                    due 2023
                
                
                50,000
                
                
                50,000* 
3.350%
                    due 2033
                
                
                -
                
                
                30,000Total
                    unsecured notes
                
                
                481,000
                
                
                511,000
                
                
                
                
                
                
                
                
                77,400
                
                
                14,500
                
                
                558,400
                
                
                525,500Preferred
                    stock subject to mandatory redemption
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                -
                
                
                12,750Capital
                    lease
                    obligations (Note 6)
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                3,312
                
                
                5,223Net
                    unamortized discount on debt
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                (9,324
                )
                
                (9,053
                )Long-term
                    debt
                    due within one year
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                (280,255
                )
                
                (398,263
                )Total
                    long-term debt and other long-term obligations
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                1,019,642
                
                
                1,114,914**TOTAL
                    CAPITALIZATION**
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                $
                3,596,903
                
                $
                3,708,793*
                    Denotes
                    variable rate issue with applicable year-end December 31, 2005
                    interest
                    rate shown.The
                    accompanying Notes to Consolidated Financial Statements are an
                    integral
                    part of these statements.
    23
  **OHIO
                    EDISON COMPANY****CONSOLIDATED
                    STATEMENTS OF COMMON STOCKHOLDER'S EQUITY****Accumulated****Other****Comprehensive**
                
                **Number**
                
                **Carrying**
                
                **Comprehensive**
                
                **Retained****Income**
                
                **of
                    Shares**
                
                **Value**
                
                **Income
                    (Loss)**
                
                **Earnings*****(Dollars
                    in thousands)***Balance,
                    January 1, 2003
                
                
                
                
                
                100
                
                $
                2,098,729
                
                $
                (59,495
                )
                $
                800,021Net
                    income
                
                $
                324,645
                
                
                
                
                
                
                
                
                
                
                
                324,645Minimum
                    liability for unfunded retirementbenefits,
                    net
                    of $2,014,000 of income taxes
                
                
                2,674
                
                
                
                
                
                
                
                
                2,674Unrealized
                    gain on investments, net of$12,337,000
                    of
                    income taxes
                
                
                18,128
                
                
                
                
                
                
                
                
                18,128Comprehensive
                    income
                
                $
                345,447Cash
                    dividends
                    on preferred stock
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                (2,732
                )Cash
                    dividends
                    on common stock
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                (599,000
                )Balance,
                    December 31, 2003
                
                
                
                
                
                100
                
                
                2,098,729
                
                
                (38,693
                )
                
                522,934Net
                    income
                
                $
                342,766
                
                
                
                
                
                
                
                
                
                
                
                342,766Minimum
                    liability for unfunded retirementbenefits,
                    net
                    of ($5,516,000) of income taxes
                
                
                (7,552
                )
                
                
                
                
                
                
                
                (7,552
                )Unrealized
                    loss on investments, net of($533,000)
                    of
                    income taxes
                
                
                (873
                )
                
                
                
                
                
                
                
                (873
                )Comprehensive
                    income
                
                $
                334,341Cash
                    dividends
                    on preferred stock
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                (2,502
                )Cash
                    dividends
                    on common stock
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                (421,000
                )Balance,
                    December 31, 2004
                
                
                
                
                
                100
                
                
                2,098,729
                
                
                (47,118
                )
                
                442,198Net
                    income
                
                $
                314,055
                
                
                
                
                
                
                
                
                
                
                
                314,055Minimum
                    liability for unfunded retirementbenefits,
                    net
                    of $49,027,000 of income taxes
                
                
                69,463
                
                
                
                
                
                
                
                
                69,463Unrealized
                    loss on investments, net of($13,068,000)
                    of income taxes
                
                
                (18,251
                )
                
                
                
                
                
                
                
                (18,251
                )Comprehensive
                    income
                
                $
                365,267Affiliated
                    company asset transfers
                
                
                
                
                
                
                
                
                198,147
                
                
                
                
                
                (106,774
                )Restricted
                    stock units
                
                
                
                
                
                
                
                
                32Preferred
                    stock redemption adjustment
                
                
                
                
                
                
                
                
                345Cash
                    dividends
                    on preferred stock
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                (2,635
                )Cash
                    dividends
                    on common stock
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                (446,000
                )Balance,
                    December 31, 2005
                
                
                
                
                
                100
                
                $
                2,297,253
                
                $
                4,094
                
                $
                200,844
   **CONSOLIDATED
                      STATEMENTS OF PREFERRED STOCK****Not
                      Subject to**
                  
                  **Subject
                      to****Mandatory
                      Redemption**
                  
                  **Mandatory
                      Redemption*****Number**
                  
                  **Par**
                  
                  **Number**
                  
                  **Par****of
                      Shares**
                  
                  **Value**
                  
                  **of
                      Shares**
                  
                  **Value*****(Dollars
                      in thousands)***Balance,
                      January 1, 2003
                  
                  
                  1,000,699
                  
                  $
                  100,070
                  
                  
                  142,500
                  
                  $
                  14,250Redemptions-7.625%
                      Series
                  
                  
                  
                  
                  
                  
                  
                  
                  (7,500
                  )
                  
                  (750
                  )Balance,
                      December 31, 2003
                  
                  
                  1,000,699
                  
                  
                  100,070
                  
                  
                  135,000
                  
                  
                  13,500Redemptions-7.625%
                      Series
                  
                  
                  
                  
                  
                  
                  
                  
                  (7,500
                  )
                  
                  (750
                  )Balance,
                      December 31, 2004
                  
                  
                  1,000,699
                  
                  
                  100,070
                  
                  
                  127,500
                  
                  
                  12,750Redemptions-7.750%
                      Series
                  
                  
                  (250,000
                  )
                  
                  (25,000
                  )7.625%
                      Series
                  
                  
                  
                  
                  
                  
                  
                  
                  (127,500
                  )
                  
                  (12,750
                  )Balance,
                      December 31, 2005
                  
                  
                  750,699
                  
                  $
                  75,070
                  
                  
                  -
                  
                  $
                  -*
                      Preferred
                      stock subject to mandatory redemption is classified as debt
                      under SFAS
                      150.The
                      accompanying Notes to Consolidated Financial Statements are
                      an integral
                      part of these statements.
   24
  **OHIO
                      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
                  
                  $
                  314,055
                  
                  $
                  342,766
                  
                  $
                  324,645Adjustments
                      to
                      reconcile net income to net cash fromoperating
                      activities -Provision
                      for
                      depreciation
                  
                  
                  108,583
                  
                  
                  122,413
                  
                  
                  117,895Amortization
                      of regulatory assets
                  
                  
                  457,205
                  
                  
                  411,326
                  
                  
                  393,409Deferral
                      of
                      new regulatory assets
                  
                  
                  (151,032
                  )
                  
                  (100,633
                  )
                  
                  (73,183
                  )Nuclear
                      fuel
                      and lease amortization
                  
                  
                  45,769
                  
                  
                  42,811
                  
                  
                  39,317Deferred
                      lease
                      costs
                  
                  
                  (6,365
                  )
                  
                  (5,170
                  )
                  
                  (4,183
                  )Deferred
                      income taxes and investment tax credits, net
                  
                  
                  (29,750
                  )
                  
                  (44,469
                  )
                  
                  (110,677
                  )Accrued
                      compensation and retirement benefits
                  
                  
                  14,506
                  
                  
                  35,840
                  
                  
                  33,065Cumulative
                      effect of accounting changes
                  
                  
                  16,343
                  
                  
                  -
                  
                  
                  (31,720
                  )Pension
                      trust
                      contribution
                  
                  
                  (106,760
                  )
                  
                  (72,763
                  )
                  
                  -Decrease
                      (increase) in operating assets-Receivables
                  
                  
                  84,688
                  
                  
                  209,130
                  
                  
                  170,492Materials
                      and
                      supplies
                  
                  
                  (3,367
                  )
                  
                  (10,259
                  )
                  
                  (2,038
                  )Prepayments
                      and other current assets
                  
                  
                  (1,778
                  )
                  
                  1,286
                  
                  
                  (2,586
                  )Increase
                      (decrease) in operating liabilities-Accounts
                      payable
                  
                  
                  45,149
                  
                  
                  (80,738
                  )
                  
                  132,983Accrued
                      taxes
                  
                  
                  10,470
                  
                  
                  (406,945
                  )
                  
                  94,281Accrued
                      interest
                  
                  
                  (3,659
                  )
                  
                  (6,722
                  )
                  
                  (9,495
                  )Electric
                      service prepayment programs
                  
                  
                  121,692
                  
                  
                  -
                  
                  
                  -Other
                  
                  
                  (464
                  )
                  
                  (21,519
                  )
                  
                  (858
                  )Net
                      cash
                      provided from operating activities
                  
                  
                  915,285
                  
                  
                  416,354
                  
                  
                  1,071,347**CASH
                      FLOWS FROM FINANCING ACTIVITIES:**New
                      Financing-Long-term
                      debt
                  
                  
                  146,450
                  
                  
                  30,000
                  
                  
                  365,000Short-term
                      borrowings, net
                  
                  
                  26,404
                  
                  
                  -
                  
                  
                  -Redemptions
                      and Repayments-Preferred
                      stock
                  
                  
                  (37,750
                  )
                  
                  (750
                  )
                  
                  (750
                  )Long-term
                      debt
                  
                  
                  (414,020
                  )
                  
                  (170,997
                  )
                  
                  (519,506
                  )Short-term
                      borrowings, net
                  
                  
                  -
                  
                  
                  (4,015
                  )
                  
                  (224,788
                  )Dividend
                      Payments-Common
                      stock
                  
                  
                  (446,000
                  )
                  
                  (421,000
                  )
                  
                  (599,000
                  )Preferred
                      stock
                  
                  
                  (2,635
                  )
                  
                  (2,502
                  )
                  
                  (2,732
                  )Net
                      cash used
                      for financing activities
                  
                  
                  (727,551
                  )
                  
                  (569,264
                  )
                  
                  (981,776
                  )**CASH
                      FLOWS FROM INVESTING ACTIVITIES:**Property
                      additions
                  
                  
                  (266,823
                  )
                  
                  (235,022
                  )
                  
                  (189,019
                  )Contributions
                      to nuclear decommissioning trusts
                  
                  
                  (31,540
                  )
                  
                  (31,540
                  )
                  
                  (31,540
                  )Loan
                      repayments from (payments to) associated companies, net
                  
                  
                  (35,553
                  )
                  
                  120,706
                  
                  
                  65,200Collection
                      of
                      principal on long-term notes receivable
                  
                  
                  199,848
                  
                  
                  7,348
                  
                  
                  1,201Proceeds
                      from
                      certificates of deposit
                  
                  
                  -
                  
                  
                  277,763
                  
                  
                  -Other
                  
                  
                  (53,967
                  )
                  
                  13,002
                  
                  
                  45,958Net
                      cash
                      provided from (used for) investing activities
                  
                  
                  (188,035
                  )
                  
                  152,257
                  
                  
                  (108,200
                  )Net
                      increase
                      (decrease) in cash and cash equivalents
                  
                  
                  (301
                  )
                  
                  (653
                  )
                  
                  (18,629
                  )Cash
                      and cash
                      equivalents at beginning of year
                  
                  
                  1,230
                  
                  
                  1,883
                  
                  
                  20,512Cash
                      and cash
                      equivalents at end of year
                  
                  $
                  929
                  
                  $
                  1,230
                  
                  $
                  1,883**SUPPLEMENTAL
                      CASH FLOW INFORMATION:**Cash
                      Paid
                      During the Year-Interest
                      (net
                      of amounts capitalized)
                  
                  $
                  67,239
                  
                  $
                  65,765
                  
                  $
                  103,632Income
                      taxes
                  
                  $
                  285,819
                  
                  $
                  419,123
                  
                  $
                  250,564The
                      accompanying Notes to Consolidated Financial Statements are
                      an integral
                      part of these statements.
     25
   **OHIO
                    EDISON COMPANY****CONSOLIDATED
                    STATEMENTS OF TAXES****For
                    the Years Ended December 31,**
                
                
                
                **2005**
                
                **2004**
                
                **2003*****(In
                    thousands)*****GENERAL
                    TAXES:**Ohio
                    kilowatt-hour excise*
                
                
                
                
                $
                94,085
                
                $
                91,811
                
                $
                91,296State
                    gross
                    receipts*
                
                
                
                
                
                20,425
                
                
                19,234
                
                
                18,028Real
                    and
                    personal property
                
                
                
                
                
                67,438
                
                
                58,000
                
                
                51,074Social
                    security and unemployment
                
                
                
                
                
                7,481
                
                
                7,048
                
                
                6,992Other
                
                
                
                
                
                3,855
                
                
                4,430
                
                
                2,688Total
                    general
                    taxes
                
                
                
                
                $
                193,284
                
                $
                180,523
                
                $
                170,078**PROVISION
                    FOR INCOME TAXES:**Currently
                    payable-Federal
                
                
                
                
                $
                265,875
                
                $
                246,865
                
                $
                270,345State
                
                
                
                
                
                73,870
                
                
                75,907
                
                
                81,505339,745
                
                
                322,772
                
                
                351,850Deferred,
                    net-Federal
                
                
                
                
                
                (60,252
                )
                
                (23,668
                )
                
                (57,503
                )State
                
                
                
                
                
                36,798
                
                
                (5,512
                )
                
                (16,038
                )(23,454
                )
                
                (29,180
                )
                
                (73,541
                )Investment
                    tax
                    credit amortization
                
                
                
                
                
                (15,519
                )
                
                (15,289
                )
                
                (14,747
                )Total
                    provision for income taxes
                
                
                
                
                $
                300,772
                
                $
                278,303
                
                $
                263,562**INCOME
                    STATEMENT CLASSIFICATION****OF
                    PROVISION FOR INCOME TAXES:**Operating
                    income
                
                
                
                
                $
                297,160
                
                $
                257,114
                
                $
                216,979Other
                    income
                
                
                
                
                
                12,835
                
                
                21,189
                
                
                24,194Cumulative
                    effect of accounting changes
                
                
                
                
                
                (9,223
                )
                
                -
                
                
                22,389Total
                    provision for income taxes
                
                
                
                
                $
                300,772
                
                $
                278,303
                
                $
                263,562**RECONCILIATION
                    OF FEDERAL INCOME TAX****EXPENSE
                    AT STATUTORY RATE TO TOTAL****PROVISION
                    FOR INCOME TAXES:**Book
                    income
                    before provision for income taxes
                
                
                
                
                $
                614,827
                
                $
                621,069
                
                $
                588,207Federal
                    income
                    tax expense at statutory rate
                
                
                
                
                $
                215,189
                
                $
                217,374
                
                $
                205,872Increases
                    (reductions) in taxes resulting from-Amortization
                    of investment tax credits
                
                
                
                
                
                (15,519
                )
                
                (15,289
                )
                
                (14,747
                )State
                    income
                    taxes, net of federal income tax benefit
                
                
                
                
                
                71,935
                
                
                45,757
                
                
                42,554Amortization
                    of tax regulatory assets
                
                
                
                
                
                7,341
                
                
                6,130
                
                
                6,144Penalites
                
                
                
                
                
                2,975
                
                
                -
                
                
                -Competitive
                    transition charge
                
                
                
                
                
                31,934
                
                
                27,889
                
                
                27,075Low
                    income
                    housing and franchise credits
                
                
                
                
                
                (6,796
                )
                
                (8,615
                )
                
                (8,574
                )Other,
                    net
                
                
                
                
                
                (6,287
                )
                
                5,057
                
                
                5,238Total
                    provision for income taxes
                
                
                
                
                $
                300,772
                
                $
                278,303
                
                $
                263,562**ACCUMULATED
                    DEFERRED INCOME TAXES AS OF****DECEMBER
                    31:**Property
                    basis
                    differences
                
                
                
                
                $
                478,599
                
                $
                451,269
                
                $
                406,783Allowance
                    for
                    equity funds used during construction
                
                
                
                
                
                27,730
                
                
                27,730
                
                
                30,493Regulatory
                    transition charge
                
                
                
                
                
                6,653
                
                
                154,015
                
                
                345,723Asset
                    retirement obligations
                
                
                
                
                
                -
                
                
                21,253
                
                
                17,394Customer
                    receivables for future income taxes
                
                
                
                
                
                33,946
                
                
                39,266
                
                
                44,382Deferred
                    sale
                    and leaseback costs
                
                
                
                
                
                (59,225
                )
                
                (63,432
                )
                
                (67,837
                )Unamortized
                    investment tax credits
                
                
                
                
                
                (9,605
                )
                
                (23,510
                )
                
                (29,031
                )Deferred
                    gain
                    for asset sale- affiliated companies
                
                
                
                
                
                50,304
                
                
                51,716
                
                
                61,115Other
                    comprehensive income
                
                
                
                
                
                2,689
                
                
                (33,268
                )
                
                (27,219
                )Retirement
                    benefits
                
                
                
                
                
                30,849
                
                
                (6,202
                )
                
                (29,676
                )Shopping
                    incentive deferral
                
                
                
                
                
                123,029
                
                
                94,002
                
                
                57,731Other
                
                
                
                
                
                84,062
                
                
                53,437
                
                
                57,833Net
                    deferred
                    income tax liability
                
                
                
                
                $
                769,031
                
                $
                766,276
                
                $
                867,691*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.
   26
  **NOTES
        TO
        CONSOLIDATED FINANCIAL STATEMENTS**





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





The
      consolidated
      financial statements include OE (Company) and its wholly owned subsidiaries.
      Penn is the Company's principal operating subsidiary. 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, TE, ATSI, JCP&L, Met-Ed and Penelec.
      In the fourth quarter of 2005, the Companies completed the intra-system
      transfers of their non-nuclear and nuclear generation assets to FGCO and NGC,
      respectively. See Note 14 - FirstEnergy Intra-System Generation Asset
      Transfers for further discussion.





The
      Companies follow
      GAAP and comply with the regulations, orders, policies and practices prescribed
      by the SEC, PUCO, the PPUC and the FERC. The preparation of financial statements
      in conformity with GAAP requires management to make periodic estimates and
      assumptions that affect the reported amounts of assets, liabilities, revenues
      and expenses and the disclosure of contingent assets and liabilities. Actual
      results could differ from these estimates.





The
      Company
      consolidates all majority-owned subsidiaries over which the Company exercises
      control and, when applicable, entities for which the Company has a controlling
      financial interest. Intercompany transactions and balances are eliminated in
      consolidation. Investments in non -consolidated
      affiliates (20-50% owned companies, joint ventures and partnerships) over which
      the Company has the ability to exercise significant influence, but not control,
      are accounted for on the equity basis.





Unless
      otherwise
      indicated, defined terms used herein have the meanings set forth in the
      accompanying Glossary of Terms.





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





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





The
      Companies
      account for the effects of regulation through the application of SFAS 71
      since their 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
      Companies
      recognize, as regulatory assets, costs which the FERC, PUCO and PPUC have
      authorized for recovery from customers in future periods or for which
      authorization is probable. Without the probability of such authorization, costs
      currently recorded as regulatory assets would have been charged to income as
      incurred. All regulatory assets are expected to be recovered from customers
      under the Companies' respective transition and rate restructuring plans. Based
      on those plans, the Companies continue to bill and collect cost-based rates
      for
      their transmission and distribution services, which remain regulated;
      accordingly, it is appropriate that the Companies c ontinue
      the
      application of SFAS 71 to those operations.


27


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





**2005***
            
            **2004******(In
                millions)***Regulatory
                transition costs
            
            $
            369
            
            $
            835Customer
                shopping incentives
            
            
            325
            
            
            228Customer
                receivables for future income taxes
            
            
            88
            
            
            99Loss
                on
                reacquired debt
            
            
            22
            
            
            23Asset
                removal
                costs
            
            
            (80
            )
            
            (72
            )MISO
                transmission costs
            
            
            49
            
            
            -Other
            
            
            2
            
            
            3Total
            
            $
            775
            
            $
            1,116





*
            Penn
                had net
                regulatory liabilities of approximately $59 million and
                $19 million included in Other Noncurrent Liabilities on the
                Consolidated Balance Sheets as of December 31, 2005 and 2004,
                respectively.





The
      Company has been
      deferring customer shopping incentives and interest costs (Extended RTC) as
      new
      regulatory assets in accordance with its prior transition and rate stabilization
      plans. As a result of the RCP approved in January 2006, the Extended RTC balance
      ($325 million as of December 31, 2005) was reduced on January 1,
      2006 by $75 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 as of December 31, 2008. At the end of the recovery period, any
      remaining unamortized regulatory transition costs and Extended RTC balances
      will
      be eliminated, first, by applying any remaining cost of removal regulatory
      liability balance; any remaining regulatory transition costs and Extended RTC
      balances would be written off. In addition, the RCP allowed the Ohio Companies
      to defer and capitalize certain distribution costs during the period
      January 1, 2006 through December 31, 2008, not to exceed
      $150 million in each of the years 2006, 2007 and 2008. These deferrals will
      be recovered in distribution rates effective on or after January 1, 2009.
      See Note 9 for further discussion of the recovery of the shopping
      incentives and the new cost deferrals.





*Transition
      Cost
      Amortization-*





The
      Company
      amortizes transition costs (see Regulatory Matters - Ohio) using the effective
      interest method. Extended RTC amortization will be equal to the related revenue
      recovery that is recognized. The following table provides the estimated net
      amortization of regulatory transition costs and Extended RTC (including
      associated carrying charges) under the RCP for the period 2006 through
      2008:





**Amortization****Period**
            
            **Amortization*****(In
                millions)***2006
            
            $
            1692007
            
            
            1762008
            
            
            198**Total
                Amortization**
            
            **$**
            **543**





**(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
      Companies'
      principal business is providing electric service to customers in Ohio and
      Pennsylvania. The Companies' 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 Companies accrue
      the
      estimated unbilled amount receivable as revenue and reverse the related prior
      period estimate.


28


Receivables from customers include sales to residential, commercial and
      industrial customers 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 Companies' customers. Total customer receivables
      were
      $291 million (billed - $177 million and unbilled - $114 million) and
      $274 million (billed - $172 million and unbilled - $102 million)
      as of December 31, 2005 and 2004, respectively.





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





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





The
      Companies
      provide for depreciation on a straight-line basis at various rates over the
      estimated lives of property included in plant in service. The annual composite
      rate for the Company's electric plant was approximately 2.1% in 2005, 2.3%
      in
      2004 and 2.2% in 2003. The annual composite rate for Penn's electric plant
      was
      approximately 2.4% in 2005 and 2.2% in 2004 and 2003.





*Asset
      Retirement
      Obligations*




The
      Companies
      recognize a liability for retirement obligations associated with tangible assets
      in accordance with SFAS 143 and FIN 47. These standards require
      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 value of the long-lived asset and depreciated over time, as
      described further in Note 11, "Asset Retirement Obligations".





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





*Long-Lived
      Assets-*





The
      Companies
      evaluate the carrying value of their 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.





*Investments-*





The
      Company
      periodically evaluates its investments for impairment, including
      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 5.





**(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, AOCL consisted of unrealized gains on investments in
      securities available for sale of $4 million. As of December 31, 2004,
      accumulated other comprehensive loss consisted of a minimum liability for
      unfunded retirement benefits of $69 million and unrealized gains on
      investments in securities available for sale of
      $22 million.


29


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





Results
      in 2005 include an after-tax charge of $16 million recorded upon the
      adoption of FIN 47 in December 2005. OE identified applicable legal
      obligations as defined under the new standard at its retired generating units,
      substation control rooms, service center buildings, line shops and office
      buildings, identifying asbestos as the primary conditional ARO. OE recorded
      a
      conditional ARO liability of $27 million, including accumulated accretion
      for the period from the date the liability was incurred to the date of adoption,
      an asset retirement cost of $9 million recorded as part of the carrying
      amount of the related long-lived asset, and offsetting accumulated depreciation
      of $9 million. OE charged regulatory
      liabilities for $1 million upon adoption of FIN 47 for the transition
      amounts related to establishing the ARO for asbestos removal from substation
      control rooms and service center buildings. The remaining cumulative effect
      adjustment for unrecognized depreciation and accretion of $26 million was
      charged to income ($16 million, net of tax). The adoption of FIN 47 had an
      immaterial impact on Penn’s year ended December 31, 2005 results. (See Note
      11.)




Upon
      adoption of
      SFAS 143 in the first quarter of 2003, OE recorded an after-tax credit to
      net income of $32 million. The cumulative adjustment for unrecognized
      depreciation, 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 $54 million
      increase to income, or $32 million net of income taxes.





**(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 Companies are included
      in FirstEnergy's consolidated federal income tax return. The consolidated tax
      liability is allocated on a "stand-alone" company basis, with the Companies
      recognizing any tax losses or credits they contribute 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 Companies,
      CEI
      and TE. As a result, the Companies had entered into power supply agreements
      (PSA) whereby FES purchased all of the Companies' nuclear generation. In the
      fourth quarter of 2005, the Companies, CEI and TE completed the intra-system
      transfers of their generation assets to FGCO and NGC (see Note 14). This
      resulted in the elimination of the fossil generating units lease arrangement
      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
      transfer. The Companies are now receiving interest income from FGCO and NGC
      on
      the associated companies notes received in exchange for the transferred net
      assets. The Companies continue to purchase their power from FES to meet their
      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. The primary affiliated companies transactions are
      as
      follows:





**2005**
            
            **2004**
            
            **2003*****(In
                millions)*****Operating
                Revenues:**PSA
                revenues
                from FES
            
            $
            
            
            
            355
            
            $
            416
            
            $
            384Generating
                units rent from FES
            
            
            
            
            
            146
            
            
            178
            
            
            178Ground
                lease
                with ATSI
            
            
            
            
            
            12
            
            
            12
            
            
            12**Services
                Received:**Purchased
                power under PSA
            
            
            
            
            
            938
            
            
            970
            
            
            902Transmission
                expense
            
            
            
            
            
            -
            
            
            -
            
            
            65FESC
                support
                services
            
            
            
            
            
            90
            
            
            91
            
            
            116**Other
                Income:**Interest
                income from ATSI
            
            
            
            
            
            16
            
            
            16
            
            
            16Interest
                income from FES
            
            
            
            
            
            9
            
            
            9
            
            
            12Interest
                income from FirstEnergy
            
            
            
            
            
            22
            
            
            -
            
            
            -





30


FirstEnergy
      does not
      bill directly or allocate any of its costs to any subsidiary company. Costs
      are
      allocated to the Companies 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.





**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 Companies' funding policy is based on
      actuarial computations using the projected unit credit method. In the fourth
      quarter of 2005, FirstEnergy made a $500 million voluntary contribution to
      its pension plan (Companies' share was $107 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 copayments, are also available
      upon retirement to employees hired prior to January 1, 2005, their
      dependents and, under certain circumstances, their survivors. The Companies
      recognize 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.





31





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





**Obligations
                and Funded Status**
            
            **Pension
                Benefits**
            
            **Other
                Benefits****As
                of
                December 31****2005**
            
            **2004**
            
            **2005**
            
            **2004*****(In
                millions)*****Change
                in benefit obligation**Benefit
                obligation as of January 1
            
            $
            4,364
            
            $
            4,162
            
            $
            1,930
            
            $
            2,368Service
                cost
            
            
            77
            
            
            77
            
            
            40
            
            
            36Interest
                cost
            
            
            254
            
            
            252
            
            
            111
            
            
            112Plan
                participants’ contributions
            
            
            -
            
            
            -
            
            
            18
            
            
            14Plan
                amendments
            
            
            15
            
            
            -
            
            
            (312
            )
            
            (281
            )Actuarial
                (gain) loss
            
            
            310
            
            
            134
            
            
            197
            
            
            (211
            )Benefits
                paid
            
            
            (270
            )
            
            (261
            )
            
            (100
            )
            
            (108
            )Benefit
                obligation as of December 31
            
            $
            4,750
            
            $
            4,364
            
            $
            1,884
            
            $
            1,930**Change
                in fair value of plan assets**Fair
                value of
                plan assets as of January 1
            
            $
            3,969
            
            $
            3,315
            
            $
            564
            
            $
            537Actual
                return
                on plan assets
            
            
            325
            
            
            415
            
            
            33
            
            
            57Company
                contribution
            
            
            500
            
            
            500
            
            
            58
            
            
            64Plan
                participants’ contribution
            
            
            -
            
            
            -
            
            
            18
            
            
            14Benefits
                paid
            
            
            (270
            )
            
            (261
            )
            
            (100
            )
            
            (108
            )Fair
                value of
                plan assets as of December 31
            
            $
            4,524
            
            $
            3,969
            
            $
            573
            
            $
            564**Funded
                status**
            
            
            (226
            )
            $
            (395
            )
            
            (1,311
            )
            $
            (1,366
            )Unrecognized
                net actuarial loss
            
            
            1,179
            
            
            885
            
            
            899
            
            
            730Unrecognized
                prior service cost (benefit)
            
            
            70
            
            
            63
            
            
            (645
            )
            
            (378
            )Net
                asset
                (liability) recognized
            
            $
            1,023
            
            $
            553
            
            $
            (1,057
            )
            $
            (1,014
            )




**Amounts
                Recognized in the****Consolidated
                Balance Sheets****As
                of
                December 31**
            
            
            
            
            
            -Prepaid
                benefit cost
            
            $
            1,023
            
            $
            -
            
            $
            -
            
            $
            -Accrued
                benefit cost
            
            
            -
            
            
            (14
            )
            
            (1,057
            )
            
            (1,014
            )Intangible
                assets
            
            
            -
            
            
            63
            
            
            -
            
            
            -Accumulated
                other comprehensive loss
            
            
            -
            
            
            504
            
            
            -
            
            
            -Net
                amount
                recognized
            
            $
            1,023
            
            $
            553
            
            $
            (1,057
            )
            $
            (1,014
            )Companies'
                share of net amount recognized
            
            $
            225
            
            $
            118
            
            $
            (291
            )
            $
            (272
            )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






32





**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
            
            $
            177Companies'
                share of net periodic cost
            
            $
            -
            
            $
            7
            
            $
            24
            
            $
            28
            
            $
            28
            
            $
            43





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




In
      selecting an
      assumed discount rate, FirstEnergy considers currently available rates of return
      on high-quality fixed income investments expected to be available during the
      period to maturity of the pension and other postretirement benefit obligations.
      The assumed rates of return on pension plan assets consider historical market
      returns and economic forecasts for the types of investments held by the
      Companies' 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 nextyear
                (pre/post-Medicare)
            
            
            9-11
            %
            
            9-11
            %Rate
                to which
                the cost trend rate is assumed todecline
                (the
                ultimate trend rate)
            
            
            5
            %
            
            5
            %Year
                that the
                rate reaches the ultimate trendrate
                (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 Companies recognized a prepaid pension cost of $225 as of December 31,
      2005. As prescribed by SFAS 87, the Companies eliminated their additional
      minimum liability of $152 million and intangible asset of $33 million.
      In addition, the entire AOCL balance was credited by $69 million (net of
      $49 million of deferred taxes) as the fair value of trust assets exceeded
      the accumulated benefit obligation as of December 31, 2005.


33


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





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




**4.    ESOP:**




An
      ESOP Trust funds most of the matching
      contribution for FirstEnergy's 401(k) savings plan. All full-time employees
      eligible for participation in the 401(k) savings plan are covered by the ESOP.
      The ESOP borrowed $200 million from OE and acquired 10,654,114 shares of
      OE's common stock (subsequently converted to FirstEnergy common stock) through
      market purchases. Dividends on ESOP shares are used to service the debt. Shares
      are released from the ESOP on a pro rata basis as debt service payments are
      made. In 2005 the ESOP loan was refinanced ($66 million principal amount) and
      its term was extended by three years.





**5.**
            **FAIR VALUE OF FINANCIAL
                INSTRUMENTS:**





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





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


**2005**
            
            **2004****Carrying**
            
            **Fair**
            
            **Carrying**
            
            **Fair****Value**
            
            **Value**
            
            **Value**
            
            **Value*****(In
                millions)***Long-term
                debt
            
            $
            1,306
            
            $
            1,308
            
            $
            1,504
            
            $
            1,528Preferred
                stock subject to mandatory redemption
            
            
            -
            
            
            -
            
            
            13
            
            
            12$
            1,306
            
            $
            1,308
            
            $
            1,517
            
            $
            1,540




The
      fair values of
      long-term debt and other long-term obligations reflect the present value of
      the
      cash outflows relating to those securities based on the current call price,
      the
      yield to maturity or the yield to call, as deemed appropriate at the end of
      each
      respective year. The yields assumed were based on securities with similar
      characteristics offered by a corporation with credit ratings similar to the
      Companies' 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
            
            $
            32
            
            $
            32
            
            $
            137
            
            $
            137-Corporate
                debt securities(2)
            
            
            2,091
            
            
            1,841
            
            
            609
            
            
            708-Mortgage-backed
                securities
            
            
            -
            
            
            -
            
            
            1
            
            
            12,123
            
            
            1,873
            
            
            747
            
            
            846Equity
                securities(1)
            
            
            104
            
            
            104
            
            
            289
            
            
            289$
            2,227
            
            $
            1,977
            
            $
            1,036
            
            $
            1,135





(1)  Includes
      nuclear
      decommissioning trust investments.


(2)  Includes
      investments
      in lease obligation bonds (see Note 6).




34


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. As
      part of the
      intra-system nuclear generation asset transfers in the fourth quarter of 2005,
      the Companies transferred their decommissioning trust investments to NGC with
      the exception of a portion related to the OE's leasehold interests in the
      nuclear generation assets retained by the Company. The Companies have 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:


**2005**
            
            **2004****Cost**
            
            **Unrealized**
            
            **Unrealized**
            
            **Fair**
            
            **Cost**
            
            **Unrealized**
            
            **Unrealized**
            
            **Fair****Basis**
            
            **Gains**
            
            **Losses**
            
            **Value**
            
            **Basis**
            
            **Gains**
            
            **Losses**
            
            **Value*****(In
                millions)***Debt
                securities
            
            $
            37
            
            $
            -
            
            $
            -
            
            $
            37
            
            $
            186
            
            $
            3
            
            $
            1
            
            $
            188Equity
                securities
            
            
            61
            
            
            9
            
            
            3
            
            
            67
            
            
            205
            
            
            49
            
            
            6
            
            
            248$
            98
            
            $
            9
            
            $
            3
            
            $
            104
            
            $
            391
            
            $
            52
            
            $
            7
            
            $
            436




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
              
              $
              227
              
              $
              154
              
              $
              189Gross
                  realized
                  gains
              
              
              35
              
              
              25
              
              
              10Gross
                  realized
                  losses
              
              
              7
              
              
              7
              
              
              5Interest
                  and
                  dividend income
              
              
              13
              
              
              13
              
              
              10





34


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**
              **Value**
            
            **Unrealized**
              **Losses**
            
            **Fair**
              **Value**
            
            **Unrealized**
              **Losses**
            
            **Fair**
              **Value**
            
            **Unrealized**
              **Losses*****(In
                millions)***Debt
                securities
            
            $
            15
            
            $
            -
            
            $
            6
            
            $
            -
            
            $
            21
            
            $
            -Equity
                securities
            
            
            11
            
            
            1
            
            
            6
            
            
            2
            
            
            17
            
            
            3$
            26
            
            $
            1
            
            $
            12
            
            $
            2
            
            $
            38
            
            $
            3




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.





**6.**  **LEASES:**





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


35


The
      Company sold
      portions of its ownership interest in Perry Unit 1 and Beaver Valley Unit 2
      and entered into operating leases on the portions sold for basic lease terms
      of
      approximately 29 years. Subsequent to the intra-system generation assets
      transfers in the fourth quarter of 2005, the Company continues to be responsible
      during the terms of the leases, to the extent of its individual leasehold
      interests, for costs associated with the units including construction
      expenditures, operation and maintenance expenses, insurance, nuclear fuel,
      property taxes and decommissioning. The Company has the right, at the end of
      the
      respective basic lease terms, to renew the leases for up to two years. The
      Company also has 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. The basic rental payments are adjusted when applicable
      federal tax law changes.





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





**2005**
            
            **2004**
            
            **2003*****(In
                millions)***Operating
                leasesInterest
                element
            
            $
            93.3
            
            $
            94.8
            
            $
            96.8Other
            
            
            52.3
            
            
            50.4
            
            
            43.9Capital
                leasesInterest
                element
            
            
            0.8
            
            
            1.0
            
            
            1.7Other
            
            
            1.9
            
            
            1.6
            
            
            1.4Total
                rentals
            
            $
            148.3
            
            $
            147.8
            
            $
            143.8





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





**Operating
                Leases****PNBV****Capital**
            
            **Lease**
            
            **Capital****Leases**
            
            **Payments**
            
            **Trusts**
            
            **Net*****(In
                millions)***2006
            
            $
            4.2
            
            $
            145.4
            
            $
            59.5
            
            $
            85.92007
            
            
            0.3
            
            
            144.5
            
            
            59.9
            
            
            84.62008
            
            
            0.3
            
            
            144.4
            
            
            34.9
            
            
            109.52009
            
            
            0.3
            
            
            144.7
            
            
            42.1
            
            
            102.62010
            
            
            0.3
            
            
            144.9
            
            
            43.2
            
            
            101.7Years
                thereafter
            
            
            1.1
            
            
            871.7
            
            
            236.2
            
            
            635.5Total
                minimum
                lease payments
            
            
            6.5
            
            $
            1,595.6
            
            $
            475.8
            
            $
            1,119.8Executory
                costs
            
            
            (2.1
            )Net
                minimum
                lease payments
            
            
            4.4Interest
                portion
            
            
            (1.1
            )Present
                value
                of net minimum
              lease
                payments
            
            
            3.3Less
                current
                portion
            
            
            (2.1
            )Noncurrent
                portion
            
            $
            1.2




The
      Company invested
      in PNBV, which was established to purchase a portion of the lease obligation
      bonds issued on behalf of lessors in the Company’s Perry Unit 1 and Beaver
      Valley Unit 2 sale and leaseback transactions. The PNBV arrangement
      effectively reduces lease costs related to those transactions. OE has LOCs
      of
      $291 million and $134 million in connection with the sale and
      leaseback of Beaver Valley Unit 2 and Perry Unit 1,
      respectively.





**7.**  **VARIABLE
      INTEREST ENTITIES:**




FIN 46R
      addresses the consolidation of VIEs, including special-purpose entities, that
      are not controlled through voting interests or in which the equity investors
      do
      not bear the entity's residual economic risks and rewards. FirstEnergy adopted
      FIN 46R for special-purpose entities as of December 31, 2003 and for
      all other entities in the first quarter of 2004. The Company consolidates VIEs
      when it is determined to be the VIE's primary beneficiary as defined by
      FIN 46R.





Included
      in the
      Company’s consolidated financial statements is PNBV, a VIE created in 1996 to
      refinance debt originally issued in connection with sale and leaseback
      transactions.





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


36


Through
      its
      investment in PNBV, the Company has variable interests in certain owner trusts
      that acquired the interests in the Perry Plant and Beaver Valley Unit 2.
      The Company has concluded that it was not the primary beneficiary of the owner
      trusts and was therefore not required to consolidate these entities. The leases
      are accounted for as operating leases in accordance with GAAP.





The
      Company is
      exposed to losses under the sale-leaseback agreements upon the occurrence of
      certain contingent events that it considers unlikely to occur. The Company
      has a
      maximum exposure to loss under these provisions of approximately
      $1 billion, which represents the net amount of casualty value payments upon
      the occurrence of specified casualty events that render the applicable plant
      worthless. Under the sale and leaseback agreement, the Company has net minimum
      discounted lease payments of $652 million that would not be payable if the
      casualty value payments are made.





**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 increase to income taxes associated with the adjustment to net deferred
      taxes in 2005 was $32 million. Income tax expenses were reduced by
      $3 million during 2005 by the initial phase-out of the Ohio income-based
      franchise tax and phase-in of the CAT tax.


**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.





In
      May 2004, the
      PPUC issued an order approving revised reliability benchmarks and standards,
      including revised benchmarks and standards for Met-Ed, Penelec and Penn. Met-Ed,
      Penelec and Penn filed a Petition for Amendment of Benchmarks with the PPUC
      on
      May 26, 2004, due to their implementation of automated outage management
      systems following restructuring. On December 30, 2005 the ALJ recommended that
      the PPUC adopt the Joint Petition for Settlement among the parties involved
      in
      the three Companies’ request to amend the distribution reliability benchmarks,
      thereby eliminating the need for full litigation. The ALJ’s recommendation,
      adopting the revised benchmarks and standards was approved by the PPUC on
      February 9, 2006.




The
      EPACT provides
      for the creation of an ERO to establish and enforce reliability standards for
      the bulk power system, subject to FERC review. On February 3, 2006, the FERC
      adopted a rule establishing certification requirements for the ERO, as well
      as
      regional entities envisioned to assume monitoring responsibility for the new
      reliability standards.


37


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.





FirstEnergy
      believes
      it is in compliance with all current NERC reliability standards. However, it
      is
      expected that the FERC will adopt stricter reliability standards than those
      contained in the current NERC Version 0 standards. The financial impact of
      complying with the new standards cannot be determined at this time. However,
      the
      EPACT required that all prudent costs incurred to comply with the new
      reliability standards be recovered in rates.


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





*Ohio-*





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.


38


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 OE;





·
            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
                OE;





·
            Reduce
                the
                deferred shopping incentive balances as of January 1, 2006 by up to
                $75 million for OE by accelerating the application of its accumulated
                cost of removal regulatory liability;
                and





·
            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).


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 $34 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.





39


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.





*Pennsylvania-*





On
      October 11,
      2005, Penn filed a plan with the PPUC to secure electricity supply for its
      customers at set rates following the end of its transition period on
      December 31, 2006. Penn is recommending that the RFP process cover the
      period January 1, 2007 through May 31, 2008. Hearings were held on
      January 10, 2006 with Main Briefs filed on January 27, 2006 and Reply
      Briefs on February 3, 2006. On February
      17,
      2006, the ALJ issued a Recommended
      Decision
      to adopt Penn's RFP process with modifications. A PPUC vote is expected in
      April
      2006. Under Pennsylvania's electric competition law, Penn is required to secure
      generation supply for customers who do not choose alternative suppliers for
      their electricity





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





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





Under
      the Company’s
      first mortgage indenture, the Company’s consolidated retained earnings
      unrestricted for payment of cash dividends on the Company’s common stock were
      $ 197 million
      as
      of December 31, 2005.





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





All
      preferred stock
      may be redeemed by the Companies in whole, or in part, with 30-60 days’
notice.





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





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





*Other
      Long-term
      Debt-*





Each
      of the
      Companies 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 also has a 1998 general
      mortgage under which it issues mortgage bonds based upon the pledge of a like
      amount of FMB as security. These mortgage bonds therefore effectively enjoy
      the
      same lien on that property and are referred to as FMB herein. The Companies
      have
      various debt covenants under their respective financing arrangements. The most
      restrictive of their 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 exists
      cross-default provisions among financing arrangements of FirstEnergy and the
      Companies.




Based
        on the amount
        of FMB
        authenticated by the respective mortgage bond trustees through December 31,
        2005, the Company's annual sinking fund requirements for all FMB issued under
        the various mortgage indentures amounts to $30 million. The Company expects
        to deposit funds with its mortgage bond trustee in 2006 that will then be
        withdrawn upon the surrender for cancellation of a like principal amount
        of FMB,
        specifically authenticated for such purposes against unfunded property additions
        or against previously retired FMB. This method can result in minor increases
        in
        the amount of the annual sinking fund requirement.
  Sinking
      fund
      requirements for FMB and maturing long-term debt (excluding capital leases)
      for
      the next five years are:


***(In
                  millions)***2006
              
              $
              2782007
              
              
              62008
              
              
              2292009
              
              
              22010
              
              
              65







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 $221 million and $50 million in 2006 and 2008,
      respectively, representing the next times the debt holders may exercise this
      provision.





The
      Companies'
      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 $158 million and noncancelable
      municipal bond insurance policies of $749 million to pay principal of, or
      interest on, the pollution control revenue bonds. To the extent that drawings
      are made under the LOCs or the policies, the Companies are entitled to a credit
      against their obligation to repay those bonds. The Companies pay annual fees
      of
      1.7% of the amounts of the LOCs to the issuing bank and are 0.20% to 0.60%
      of
      the amounts of the policies to the insurers and are obligated to reimburse
      the
      bank or insurers, as the case may be, for any drawings thereunder.




40


OES
      Finance,
      Incorporated, a wholly owned subsidiary of the Company, had maintained
      certificates of deposits pledged as collateral to secure reimbursement
      obligations relating to certain LOCs supporting the Company's obligations to
      lessors under the Beaver Valley Unit 2 sale and leaseback arrangements. In
      June 2004, these LOCs were replaced by a new LOC which did not require the
      collateral deposits. The Company entered into a Credit Agreement pursuant to
      which a standby LOC was issued in support of the replacement LOCs and the issuer
      of the standby LOC obtained the right to pledge or assign participations in
      the
      Company's reimbursement obligations to a trust. The trust then issued and sold
      trust certificates to institutional investors that were designed to be the
      credit equivalent of an investment directly in the Company. The certificates
      of
      deposit were cancelled and the Company received cash proceeds of
      $278 million in the third quarter of 2004.


**11.**  **ASSET
      RETIREMENT OBLIGATIONS:**





In
      January 2003, the
      Companies 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
      Companies
      initially identified applicable legal obligations as defined under the standard
      for nuclear power plant decommissioning of Beaver Valley 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
      $298 million, including accumulated accretion for the period from the date
      the liability was incurred to the date of adoption. The Companies' share of
      the
      obligation to decommission these units was developed based on site specific
      studies performed by an independent engineer. The Companies 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 Companies. 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.





In
      2005, the
      Companies revised the ARO associated with Beaver Valley Unit 2 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 and Perry by
      $5 million and $6 million, respectively.





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 $104 million.





The
      Companies 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.








41




The
        Company identified applicable legal obligations as defined under the new
        standard at its retired generating units, substation control rooms, service
        center buildings, line shops and office buildings, identifying asbestos as
        the
        primary conditional ARO. As a result of adopting FIN 47 in December 2005,
        the Company recorded a conditional ARO liability of $27 million (including
        accumulated accretion for the period from the date the liability was incurred
        to
        the date of adoption), an asset retirement cost of $9 million (recorded as
        part of the carrying amount of the related long-lived asset) and accumulated
        depreciation of $9 million. The Company recognized a regulatory liability
        of $1 million upon adoption of FIN 47 for the transition amounts
        related to establishing the ARO for asbestos removal from substation control
        room and service center buildings, therefore requiring a $26 million
        cumulative effect adjustment ($16 million net of tax) for unrecognized
        depreciation and accretion to be recorded as of December 31, 2005. The
        obligation to remediate asbestos, lead paint abatement and other remediation
        costs at the retired generating units was developed based on site specific
        studies performed by an independent engineer. The costs of remediation at
        the
        substation control rooms, service center buildings, line shops and office
        buildings were based on costs incurred during recent remediation projects
        performed at each of these locations, respectively. The conditional ARO
        liability was the developed utilizing an expected cash flow approach (as
        discussed in SFAC 7) to measure the fair value of the ARO. The Company used
        a probability weighted analysis to estimate when remediation payments would
        begin. The adoption of FIN 47 had an immaterial impact on Penn’s year ended
        December 31, 2005 results. The effect on income as if FIN 47 had been
        applied during 2004 and 2003 was immaterial.


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





**2005**
            
            **2004****ARO
                Reconciliation**
            
            ***(In
                millions)***Balance
                at
                beginning of year
            
            $
            339
            
            
            318Transfers
                to
                FGCO and NGC
            
            
            (293
            )
            
            -Accretion
            
            
            21
            
            
            21Revisions
                in
                estimated cash flows
            
            
            (11
            )
            
            -FIN
                47
                ARO
            
            
            27
            
            
            -Balance
                at end
                of year
            
            $
            83
            
            
            339





**1** **2.**  **SHORT-TERM
      BORROWINGS AND BANK LINES OF CREDIT:**





Short-term
      borrowings outstanding as of December 31, 2005, consisted of $ 4 million
      of OE
      bank borrowings, $140 million of OES Capital, Incorporated and
      $58 million of borrowings from affiliates. OES Capital is a wholly owned
      subsidiary of OE whose borrowings are secured by customer accounts receivable
      purchased from OE. OES Capital can borrow up to $170 million under a
      receivables financing arrangement at rates based on certain bank commercial
      paper and is required to pay an annual fee of 0.20% on the amount of the entire
      finance limit. The receivables financing agreement expired in February 2006
      and
      was renewed until October 2006. Penn Funding, a wholly owned subsidiary of
      Penn,
      is a limited liability company whose borrowings are secured by customer accounts
      receivable purchased from Penn. It can borrow up to $25 million under a
      receivables financing arrangement at rates based on bank commercial paper rates.
      The financing arrangements require payment of an annual facility fee of 0.15%
      on
      the entire finance limit. Penn's receivables financing agreements expire in
      June
      2006. As separate legal entities with separate creditors, OES Capital and Penn
      Funding would have to satisfy their separate obligations to creditors before
      any
      of their remaining assets could be made available to OE and Penn,
      respectively.





In June 2005,
      FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as
      Borrowers, entered into a syndicated $2 billion five-year revolving credit
      facility 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. OE's and Penn’s combined borrowing limits under the
      facility are $550 million.





The
      weighted average
      interest rates on short-term borrowings outstanding as of December 31, 2005
      and 2004 were 4.2% and 2.3%, 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
      interests in the Beaver Valley Unit 2 and the Perry Plant, 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 $34.4 million
      per incident but not more than $5.1 million in any one year for each
      incident.





42






The
      Company is also
      insured as to its respective interests in Beaver Valley and Perry under policies
      issued to the operating company for each 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
      $149.8 million of insurance coverage for replacement power costs for its
      respective leasehold interests in Beaver Valley and Perry. Under these policies,
      the Company can be assessed a maximum of approximately $8.1 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.


**(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.





*W.
      H. Sammis
      Plant*





In
      1999 and 2000,
      the EPA issued NOV or Compliance Orders to nine utilities alleging violations
      of
      the Clean Air Act based on operation and maintenance of 44 power plants,
      including the W. H. Sammis Plant, which was owned at that time by OE and Penn.
      In addition, the DOJ filed eight civil complaints against various investor-owned
      utilities, including a complaint against OE and Penn in the U.S. District Court
      for the Southern District of Ohio. These cases are referred to as New Source
      Review cases. On March 18, 2005, OE and Penn announced that they had
      reached a settlement with the EPA, the DOJ and three states (Connecticut, New
      Jersey, and New York) that resolved all issues related to the W. H. Sammis
      Plant
      New Source Review litigation. This
      settlement
      agreement was approved by the Court on July 11, 2005, and requires
      reductions of NO x and SO 2 emissions at the
      W. H. Sammis Plant and other coal fired plants through the installation of
      pollution control devices and provides for stipulated penalties for failure
      to
      install and operate such pollution controls in accordance with that
      agreement. Consequently, if OE
      and Penn fail to install such pollution control devices, for any reason,
      including, but not limited to, the failure of any third-party contractor to
      timely meet its delivery obligations for such devices, OE and Penn could be
      exposed to penalties under the settlement agreement. Capital expenditures
      necessary to meet those requirements are currently estimated to be
      $1.5 billion (the primary portion of which is expected to be spent in the
      2008 to 2011 time period). On August 26, 2005, FGCO entered into an
      agreement with Bechtel Power Corporation (Bechtel), under which Bechtel will
      engineer, procure, and construct air quality control systems for the reduction
      of sulfur dioxide emissions. The settlement agreement also requires OE and
      Penn
      to spend up to $25 million toward environmentally beneficial projects,
      which include wind energy purchased power agreements over a 20-year term. OE
      and
      Penn agreed to pay a civil penalty of $8.5 million. Results in 2005
      included the penalties payable by OE and Penn of $7.8 million and
      $0.7 million, respectively. OE and Penn also recognized liabilities of
      $9.2 million and $0.8 million,  respectively,
      for
      probable future cash contributions toward environmentally beneficial
      projects.





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




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





43





*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.


FirstEnergy
      companies also are defending six separate complaint cases before the PUCO
      relating to the August 14, 2003 power outage. Two cases were originally
      filed in Ohio State courts but were subsequently dismissed for lack of subject
      matter jurisdiction and further appeals were unsuccessful. In these cases the
      individual complainants—three in one case and four in the other—sought to
      represent others as part of a class action. The PUCO dismissed the class
      allegations, stating that its rules of practice do not provide for class action
      complaints. Of the four other pending PUCO complaint cases, three were filed
      by
      various insurance carriers either in their own name as subrogees or in the
      name
      of their insured. In each of the four cases, the carrier seeks reimbursement
      from various FirstEnergy companies (and, in one case, from PJM, MISO and
      American Electric Power Company 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 Companies, CEI and TE with the exception of leasehold
      interests of the Company 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 (21.66%) and
      Perry (12.58%), the transfer included the Companies' prior owned interests
      in
      Beaver Valley Unit 1 (100.00%), Beaver Valley Unit 2 (33.96%) and Perry
      (22.66%).


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


44




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




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





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





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





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





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




The
          difference
          (approximately $177.7 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 OE and Penn promissory
          notes of approximately $1.0 billion and $0.1 billion, respectively, that
          are secured by liens on the units purchased, bear interest at a rate per
          annum
          based on the weighted cost of OE’s and Penn's long-term debt (3.98% and 5.39%,
          respectively) and mature twenty years after the date of issuance. FGCO
          may
          pre-pay a portion of the promissory notes through refunding from time to
          time of
          OE’s and Penn's outstanding pollution control debt. The timing of any refunding
          will be subject to market conditions and other factors.
 45





On
      December 16,
      2005, the Companies completed the intra-system transfer of their respective
      ownership in the nuclear generation assets to NGC through an asset spin-off
      by
      way of dividend. 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 $20.5 million) between the purchase price and
          the net
          book value at the date of transfer was credited to equity. Pursuant to
          the OE
          Contribution Agreement, OE made a capital contribution to NGC of its undivided
          ownership interests in certain nuclear generation assets, the common stock
          of
          OES Nuclear Incorporated (OES Nuclear), a wholly owned subsidiary of OE
          that
          held an undivided interest in the Perry Nuclear Power Plant, together with
          associated decommissioning trust funds and other related assets. In connection
          with the contribution, NGC assumed other liabilities associated with the
          transferred assets. In addition, OE and Penn received promissory notes
          from NGC
          in the principal amount of approximately $371.5 million and $240.4 million,
          respectively, representing the net book value of the contributed assets
          as of
          September 30, 2005, less other liabilities assumed. The notes bear interest
          at a rate per annum based on OE’s and Penn's weighted average cost of long-term
          debt (3.98% and 5.39%, respectively), mature twenty years from the date
          of
          issuance, and are subject to prepayment at any time, in whole or in part,
          by
          NGC. Following the capital contribution, OES Nuclear was merged with and
          into
          NGC, and OE distributed the common stock of NGC as a dividend (approximately
          $106.8 million) to FirstEnergy, such that NGC is currently a direct wholly
          owned
          subsidiary of FirstEnergy.


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





The
      transfers are
      expected to affect the Companies' near-term future results with reductions
      in
      revenues and expenses. Revenues will be reduced due to the termination of the
      sale of the Companies' nuclear-generated KWH and the lease of their non-nuclear
      generation assets arrangements with FES. The Companies' 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. OE will retain the nuclear-generated KWH sales
      arrangement and the portion of expenses related to its retained leasehold
      interests in Perry and Beaver Valley Unit 2. In addition, the Companies will
      receive interest income from associated company notes receivable from FGCO
      and
      NGC for the transfer of their generation net assets and eliminate the interest
      expense on certain pollution control notes to be transferred to FGCO and NGC.
      FES will continue to provide the PLR requirements of the Companies under revised
      purchased power arrangements for a three-year period beginning January 1, 2006
      (see Note 9 - Regulatory Matters).





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





**Assets
                Transferred (In millions)**Property,
                plant and equipment
            
            $
            1,592Other
                property
                and investments
            
            
            372Current
                assets
            
            
            94Deferred
                charges
            
            
            -$
            2,058**Liabilities
                Related to Assets Transferred**Long-term
                debt
            
            $
            104Current
                liabilities
            
            
            -Noncurrent
                liabilities
            
            
            261$
            365**Net
                Assets Transferred**
            
            $
            1,693




46





**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 Companies are currently evaluating this FSP Issue
      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 Companies 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 Companies 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
      this Statement amending APB 29, which was based on the principle that
      nonmonetary assets should be measured based on the fair value of the assets
      exchanged. The guidance in APB 29 included certain exceptions to that
      principle. SFAS 153 eliminates the exception from fair value measurement
      for nonmonetary exchanges of similar productive assets and replaces it with
      an
      exception for exchanges that do not have commercial substance. This Statement
      specifies that a nonmonetary exchange has commercial substance if the future
      cash flows of the entity are expected to change significantly as a result of
      the
      exchange. The provisions of this statement are effective for nonmonetary
      exchanges occurring in fiscal periods beginning after June 15, 2005 and are
      to be applied prospectively. The Companies are currently evaluating this
      standard but do not expect it to have a material impact on the financial
      statements.






47





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





In
      November 2004,
      the FASB issued this statement 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 Companies beginning January 1,
      2006. The Company does not expect it to have a material impact on its
      financial statements.





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





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





**March
                31,**
            
            **June
                30,**
            
            **September
                30,**
            
            **December
                31,****Three
                Months Ended**
            
            **2005**
            
            **2005**
            
            **2005**
            
            **2005*****(In
                millions)***Operating
                Revenues
            
            $
            726.3
            
            $
            716.6
            
            $
            825.8
            
            $
            706.8Operating
                Expenses and Taxes
            
            
            653.4
            
            
            667.2
            
            
            700.1
            
            
            619.4Operating
                Income
            
            
            72.9
            
            
            49.4
            
            
            125.7
            
            
            87.4Other
                Income
            
            
            0.5
            
            
            16.9
            
            
            20.0
            
            
            23.9Net
                Interest
                Charges
            
            
            16.6
            
            
            19.2
            
            
            14.3
            
            
            16.2Income
                before
                cumulative effect of accountingchange
            
            
            56.8
            
            
            47.1
            
            
            131.4
            
            
            95.1Cumulative
                Effect of Accounting Change (Net ofIncome
                Tax
                Benefit)
            
            
            -
            
            
            -
            
            
            -
            
            
            (16.3
            )Net
                Income
            
            $
            56.8
            
            $
            47.1
            
            $
            131.4
            
            $
            78.8Earnings
                on
                Common Stock
            
            $
            56.1
            
            $
            46.4
            
            $
            130.7
            
            $
            78.1








**March
                31,**
            
            **June
                30,**
            
            **September
                30,**
            
            **December
                31,****Three
                Months Ended**
            
            **2004**
            
            **2004**
            
            **2004**
            
            **2004*****(In
                millions)***Operating
                Revenues
            
            $
            743.3
            
            $
            718.4
            
            $
            766.3
            
            $
            717.6Operating
                Expenses and Taxes
            
            
            660.9
            
            
            632.2
            
            
            670.8
            
            
            646.2Operating
                Income
            
            
            82.4
            
            
            86.2
            
            
            95.5
            
            
            71.4Other
                Income
            
            
            12.5
            
            
            20.7
            
            
            17.2
            
            
            23.7Net
                Interest
                Charges
            
            
            18.8
            
            
            19.5
            
            
            10.0
            
            
            18.6Net
                Income
            
            $
            76.1
            
            $
            87.4
            
            $
            102.7
            
            $
            76.5Earnings
                on
                Common Stock
            
            $
            75.5
            
            $
            86.7
            
            $
            102.1
            
            $
            76.0





48