**PENNSYLVANIA
      ELECTRIC COMPANY**





**2005
      ANNUAL
      REPORT TO STOCKHOLDERS**











Pennsylvania
      Electric Company is a wholly owned electric utility operating subsidiary of
      FirstEnergy Corp. It engages in the distribution and sale of electric energy
      in
      an area of approximately 17,600 square miles in western Pennsylvania. It also
      engages in the sale, purchase and interchange of electric energy with other
      electric companies. The area it serves has a population of approximately
      1.7 million. The Company is a lessee of the property of the Waverly
      Electric Light & Power Company, which provides electric energy service in
      Waverly, New York and vicinity.
















**Contents**
            
            **Page**Glossary
                of
                Terms
            
            i-iiReport
                of
                Independent Registered Public Accounting Firm
            
            1Selected
                Financial Data
            
            2Management's
                Discussion and Analysis
            
            3-13Consolidated
                Statements of Income
            
            14Consolidated
                Balance Sheets
            
            15Consolidated
                Statements of Capitalization
            
            16Consolidated
                Statements of Common Stockholder's Equity
            
            17Consolidated
                Statements of Preferred Stock
            
            17Consolidated
                Statements of Cash Flows
            
            18Consolidated
                Statements of Taxes
            
            19Notes
                to
                Consolidated Financial Statements
            
            20-35











**GLOSSARY
      OF
      TERMS**





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





ATSI
            American
                Transmission Systems, Inc., owns and operates transmission
                facilitiesCEI
            The
                Cleveland
                Electric Illuminating Company, an Ohio electric utility operating
                subsidiaryCompanies
            OE,
                CEI, TE,
                Penn, JCP&L, Met-Ed and PenelecFES
            FirstEnergy
                Solutions Corp., provides energy-related products and
                servicesFESC
            FirstEnergy
                Service Company, provides legal, financial, and other corporate support
                servicesFirstEnergy
            FirstEnergy
                Corp., a public utility holding companyGPU
            GPU,
                Inc.,
                former parent of JCP&L, Met-Ed and Penelec, which merged with
                FirstEnergy on
              November 7,
                2001GPUS
            GPU
                Service
                Company, previously provided corporate support servicesJCP&L
            Jersey
                Central
                Power & Light Company, an affiliated New Jersey electric
                utilityMet-Ed
            Metropolitan
                Edison Company, an affiliated Pennsylvania electric
                utilityNGC
            FirstEnergy
                Nuclear Generation Corp., owns nuclear generating
                facilitiesOE
            Ohio
                Edison
                Company, an affiliated Ohio electric utilityPenelec
            Pennsylvania
                Electric CompanyPenn
            Pennsylvania
                Power Company, an affiliated Pennsylvania electric
                utilityTE
            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 Accounting Research Bulletin"ARB
            Accounting
                Research BulletinARB
                43
            ARB
                No. 43,
                "Restatement and Revision of Accounting Research
                Bulletin"ARO
            Asset
                Retirement ObligationCTC
            Competitive
                Transition ChargeECAR
            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
                CounterpartyEPACT
            Energy
                Policy
                Act of 2005FASB
            Financial
                Accounting Standards BoardFERC
            Federal
                Energy
                Regulatory CommissionFIN
                46R
            FASB
                Interpretation No. 46 (revised December 2003), "Consolidation of
                Variable
                Interest Entities"FIN
                47
            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-TemporaryImpairment
                and
                its Application to Certain Investments"GAAP
            Accounting
                Principles Generally Accepted in the United StatesIRS
            Internal
                Revenue ServiceKWH
            Kilowatt-hoursMedicare
                Act
            Medicare
                Prescription Drug, Improvement and Modernization Act of
                2003MEIUG
            Met-Ed
                Industrial Users GroupMISO
            Midwest
                Independent Transmission System Operator, Inc.Moody’s
            Moody’s
                Investors ServiceNERC
            North
                American
                Electric Reliability CouncilNUG
            Non-Utility
                GenerationOCA
            Office
                of
                Consumer Advocate





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


OCI
            Other
                Comprehensive IncomeOPEB
            Other
                Post-Employment BenefitsOSBA
            Office
                of
                Small Business AdvocateOTS
            Office
                of
                Trial StaffPICA
            Penelec
                Industrial Customer AssociationPJM
            PJM
                Interconnection L. L. C.PLR
            Provider
                of
                Last ResortPPUC
            Pennsylvania
                Public Utility CommissionPRP
            Potentially
                Responsible PartyPUCO
            Public
                Utilities Commission of OhioPUHCA
            Public
                Utility
                Holding Company ActS&P
            Standard
&
                Poor’s Ratings ServiceSEC
            United
                States
                Securities and Exchange CommissionSFAC
            Statement
                of
                Financial Accounting ConceptsSFAC
                7
            SFAC
                No. 7
                “Using Cash Flow Information and Present Value in Accounting
                Measurements”SFAS
            Statement
                of
                Financial Accounting StandardsSFAS
                71
            SFAS
                No. 71,
                "Accounting for the Effects of Certain Types of
                Regulation"SFAS
                87
            SFAS
                No. 87,
                "Employers' Accounting for Pensions"SFAS
                101
            SFAS
                No. 101,
                "Accounting for Discontinuation of Application of SFAS
                71"SFAS
                106
            SFAS
                No. 106,
                "Employers' Accounting for Postretirement Benefits Other Than
                Pensions"SFAS
                115
            SFAS
                No. 115,
                "Accounting for Certain Investments in Debt and Equity
                Securities"SFAS
                133
            SFAS
                No. 133,
                “Accounting for Derivative Instruments and Hedging
                Activities”SFAS
                142
            SFAS
                No. 142,
                "Goodwill and Other Intangible Assets"SFAS
                143
            SFAS
                No. 143,
                "Accounting for Asset Retirement Obligations"SFAS
                144
            SFAS
                No. 144,
                "Accounting for the Impairment or Disposal of Long-Lived
                Assets"SFAS
                151
            SFAS
                No. 151,
                "Inventory Costs - an amendment of ARB No. 43, Chapter
                4"SFAS
                153
            SFAS
                No. 153,
                "Exchanges of Nonmonetary Assets - an amendment of APB Opinion No.
                29"SFAS
                154
            SFAS
                No. 154,
                "Accounting Changes and Error Corrections - a replacement of APB
                Opinion
                No. 20 and FASB Statement No. 3"TMI-1
            Three
                Mile
                Island Unit 1TMI-2
            Three
                Mile
                Island Unit 2VIE
            Variable
                Interest Entity








ii


**Report
      of
      Independent Registered Public Accounting Firm**








To
      the Stockholder
      and Board of


Directors
      of
      Pennsylvania Electric 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 Pennsylvania Electric 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 9 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.





**PENNSYLVANIA
                    ELECTRIC COMPANY****SELECTED
                    FINANCIAL DATA****Nov
                    7
                    -**
                
                **Jan
                    1-****2005**
                
                **2004**
                
                **2003**
                
                **2002**
                
                **Dec.
                    31, 2001**
                
                **Nov.
                    6, 2001*****(Dollars
                    in thousands)*****GENERAL
                    FINANCIAL INFORMATION:**Operating
                    Revenues
                
                $
                1,122,025
                
                $
                1,036,070
                
                $
                974,857
                
                $
                1,027,102
                
                $
                140,062
                
                $
                834,548Operating
                    Income
                
                $
                63,977
                
                $
                73,680
                
                $
                60,245
                
                $
                88,190
                
                $
                14,341
                
                $
                70,049Income
                    Before
                    Cumulative Effectof
                    Accounting
                    Changes
                
                $
                27,553
                
                $
                36,030
                
                $
                20,237
                
                $
                50,910
                
                $
                10,795
                
                $
                23,718Net
                    Income
                
                $
                26,755
                
                $
                36,030
                
                $
                21,333
                
                $
                50,910
                
                $
                10,795
                
                $
                23,718Total
                    Assets
                
                $
                2,698,577
                
                $
                2,813,752
                
                $
                3,052,243
                
                $
                3,163,254
                
                $
                3,300,269**CAPITALIZATION
                    AS OF DECEMBER 31:**Common
                    Stockholder’s Equity
                
                $
                1,333,877
                
                $
                1,305,015
                
                $
                1,297,332
                
                $
                1,353,704
                
                $
                1,306,576Company-Obligated
                    TrustPreferred
                    Securities
                
                
                -
                
                
                -
                
                
                -
                
                
                92,214
                
                
                92,000Long-Term
                    Debt
                    and Other Long-Term Obligations
                
                
                476,504
                
                
                481,871
                
                
                438,764
                
                
                470,274
                
                
                472,400Total
                    Capitalization
                
                $
                1,810,381
                
                $
                1,786,886
                
                $
                1,736,096
                
                $
                1,916,192
                
                $
                1,870,976**CAPITALIZATION
                    RATIOS:**Common
                    Stockholder’s Equity
                
                
                73.7
                %
                
                73.0
                %
                
                74.7
                %
                
                70.7
                %
                
                69.8%Company-Obligated
                    TrustPreferred
                    Securities
                
                
                -
                
                
                -
                
                
                -
                
                
                4.8
                
                
                4.9Long-Term
                    Debt
                    and Other Long-Term Obligations
                
                
                26.3
                
                
                27.0
                
                
                25.3
                
                
                24.5
                
                
                25.3Total
                    Capitalization
                
                
                100.0
                %
                
                100.0
                %
                
                100.0
                %
                
                100.0
                %
                
                100.0%**DISTRIBUTION
                    KWH DELIVERIES (Millions):**Residential
                
                
                4,457
                
                
                4,249
                
                
                4,166
                
                
                4,196
                
                
                721
                
                
                3,264Commercial
                
                
                5,010
                
                
                4,792
                
                
                4,748
                
                
                4,753
                
                
                758
                
                
                3,733Industrial
                
                
                4,729
                
                
                4,589
                
                
                4,443
                
                
                4,336
                
                
                685
                
                
                3,658Other
                
                
                40
                
                
                39
                
                
                41
                
                
                42
                
                
                7
                
                
                34Total
                
                
                14,236
                
                
                13,669
                
                
                13,398
                
                
                13,327
                
                
                2,171
                
                
                10,689**CUSTOMERS
                    SERVED:**Residential
                
                
                506,113
                
                
                505,999
                
                
                503,738
                
                
                503,007
                
                
                502,901Commercial
                
                
                78,847
                
                
                78,519
                
                
                77,737
                
                
                77,125
                
                
                76,005Industrial
                
                
                2,458
                
                
                2,492
                
                
                2,545
                
                
                2,605
                
                
                2,652Other
                
                
                1,053
                
                
                1,056
                
                
                1,069
                
                
                1,081
                
                
                1,099Total
                
                
                588,471
                
                
                588,066
                
                
                585,089
                
                
                583,818
                
                
                582,657**NUMBER
                    OF EMPLOYEES:**
                
                
                867
                
                
                843
                
                
                887
                
                
                *****
                
                
                *****
                
                
                ******For
                    years
                    prior to 2003 Penelec's employees were employed by GPU Service
                    Company.








2





**PENNSYLVANIA
      ELECTRIC COMPANY**





**Management’s
      Discussion and Analysis of**


**Results
      of
      Operations and Financial Condition**








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





**Results
      of
      Operations**





Net
      income decreased
      to $27 million in 2005, compared to $36 million in 2004. The decrease
      in 2005 resulted from higher purchased power costs and other operating costs,
      partially offset by higher operating revenues. Net income increased to
      $36 million in 2004 from $21 million in 2003. In 2004, net income was
      higher due to higher operating revenues and other income partially offset by
      higher purchased power costs and other operating costs.





*Operating
      Revenues*





Operating
      revenues
      increased by $86 million in 2005 compared to 2004, primarily due to higher
      sales levels. Revenues from retail generation increased by $35 million due
      mainly to a total 5.9% increase in KWH sales with increases in all sectors
      (industrial - 8.5%, residential - 4.9% and commercial - 5.0%) due to unusually
      warm summer temperatures and improved economic conditions in our service area
      in
      2005 compared to 2004. Retail generation KWH sales also increased as a result
      of
      reduced customer shopping in 2005 compared to 2004 as industrial customers
      continued to return to us after switching to alternative suppliers (a 4.0
      percentage point decrease in shopping). Revenues from distribution deliveries
      increased by $11 million due to a 4.1% increase in electricity throughput,
      reflecting the effect of the warmer summer temperatures, were partially offset
      by lower unit prices. Transmission revenues increased $37 million in 2005
      compared with 2004 in part from increased loads due to warmer weather and higher
      transmission usage prices.





Operating
      revenues
      increased by $61 million in 2004 compared to 2003, primarily as a result of
      higher revenues from distribution deliveries and transmission revenues, which
      were partially offset by lower retail generation revenues. Revenues from
      distribution deliveries increased by $30 million due to higher unit prices
      and a 2.0% increase in electricity throughput with increases in all customer
      sectors. KWH deliveries increased to commercial and industrial customers
      reflecting an improving economy in our service area. Retail generation revenues
      decreased by $9 million due to lower composite prices. This decrease was
      partially offset by a 3.1% increase in retail generation KWH sales due to
      generation customers returning to us after switching to alternative suppliers.
      Transmission revenues increased $40 million in 2004 compared with 2003 due
      to an amended power supply agreement with FES, which resulted in our recognizing
      certain transmission revenues that were previously attributed to FES which
      also
      increased transmission expenses as discussed below.


3





Changes
      in electric
      generation sales and distribution deliveries in 2005 and 2004 are summarized
      in
      the following table:





**Increases
                in Distribution Deliveries**
            
            **2005**
            
            **2004**Residential
            
            
            4.9
            %
            
            2.0
            %Commercial
            
            
            4.6
            %
            
            0.9
            %Industrial
            
            
            3.1
            %
            
            3.3
            %**Total
                Increases in Distribution Deliveries**
            
            
            4.1
            %
            
            2.0
            %





*Operating
      Expenses and Taxes*





Total
      operating
      expenses and taxes increased by $96 million, or 9.9%, in 2005 and increased
      $48 million, or 5.2%, in 2004, compared to the preceding year. Higher
      purchased power costs, other operating costs and depreciation partially offset
      by lower income taxes and deferral of new regulatory assets, accounted for
      the
      increase in 2005. In 2004, the increase was due to higher purchased power costs,
      other operating costs and income taxes. The following table presents changes
      from the prior year by expense category:





**Operating
                Expenses and Taxes****-
                Changes**
            
            **2005**
            
            **2004****Increase
                (Decrease)**
            
            ***(In
                millions)***Purchased
                power costs
            
            $50
            
            $20Other
                operating costs
            
            61
            
            19Provision
                for
                depreciation
            
            
            2
            
            
            (6
            )Amortization
                of regulatory assets
            
            
            -
            
            
            7Deferral
                of
                new regulatory assets
            
            
            (3
            )
            
            -General
                taxes
            
            
            1
            
            
            1Income
                taxes
            
            
            (15
            )
            
            7**Total
                operating expenses and taxes**
            
            **$**
            **96**
            
            **$**
            **48**





Purchased
      power
      costs increased by $50 million or 8.8% in 2005, compared to the prior year.
      The increase was due primarily to a 5.6% increase in KWH purchases to meet
      the
      increased retail generation sales. Purchased power costs increased by
      $20 million or 3.7% in 2004, compared to 2003, due primarily to higher KWH
      purchased to meet increased retail generation sales requirements caused by
      reduced shopping and better economic conditions.





Other
      operating
      costs increased by $61 million or 30.9% in 2005, compared to 2004. The
      increase was the result of significantly higher transmission expenses due primarily
      to
      increased loads and higher transmission system usage charges .
      Other operating
      costs increased by $19 million or 10.5% in 2004, compared to 2003. The
      increase was due primarily to increased transmission expenses, which were
      assumed in 2004 due to a change in the power supply agreement with FES, and
      to
      higher vegetation management costs.





Depreciation
      charges
      increased in 2005 primarily due to the transfer of information system software
      assets from FESC to Penelec in 2005. Depreciation charges decreased in 2004
      compared to 2003 due to certain assets being fully depreciated in 2004.
      Amortization of regulatory assets increased in 2004 from 2003 due to a higher
      level of deferred NUG cost recovery. The deferral of new regulatory assets
      represents costs incurred for the Universal Service and Energy Conservation
      Programs that are recoverable through future rates.





*Net
      Interest
      Charges*





Interest
      on
      long-term debt decreased $1 million in 2005 due to the redemption and
      refinancing of our outstanding debt using lower-rate instruments. This decrease
      was partially offset by higher interest expense resulting from intercompany
      loans through the money pool discussed below. In 2004, net interest charges
      decreased $2 million compared to the prior year, reflecting the redemption
      of $100 million of 7.34% subordinated debentures in September 2004. This
      decrease was partially offset by interest expense resulting from intercompany
      loans through the money pool.





*Cumulative
      Effect of Accounting Change*





Results
      in 2005
      include an after-tax charge to net income of $0.8 million recorded upon the
      adoption of FIN 47 in December 2005. We identified applicable legal
      obligations as defined under the new standard at our 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, we recorded a conditional ARO liability of $1.6 million (including
      accumulated accretion for the period from the date the liability was incurred
      to
      the date of adoption), an asset retirement cost of $0.4 million (recorded
      as part of the carrying amount of the related long-lived asset), and accumulated
      depreciation of $0.2 million.





4


Upon
      adoption of
      SFAS 143 in the first quarter of 2003, we recorded an after-tax gain to net
      income of $1.1 million. The cumulative effect adjustment for unrecognized
      depreciation and accretion, offset by the reduction in the existing
      decommissioning liabilities and ceasing the accounting practice of depreciating
      non-regulated generation assets using a cost of removal component was a
      $1.9 million increase to income, or $1.1 million net of income
      taxes.





**Capital
      Resources and Liquidity**





Our
      cash
      requirements in 2005 for operating expenses, construction expenditures and
      scheduled debt maturities were met with a combination of cash from operations
      and funds from the capital markets. During 2006 and thereafter, we expect to
      meet our contractual obligations with a combination of cash from operations
      and
      funds from the capital markets.





*Changes
      in Cash
      Position*





As
      of
      December 31, 2005, we had $35,000 of cash and cash equivalents compared
      with $36,000 as of December 31, 2004. The major sources for changes in
      these balances are summarized below.





*Cash
      Flows From
      Operating Activities*





Our
      net cash
      provided from operating activities was $143 million in 2005,
      $46 million in 2004 and $16 million in 2003, summarized as follows:





**Operating
                Cash Flows**
            
            **2005**
            
            **2004**
            
            **2003*****(In
                millions)***Cash
                earnings(1)
            
            $
            77
            
            $
            112
            
            $
            88Pension
                trust
                contribution(2)
            
            
            (14
            )
            
            (30
            )
            
            -Working
                capital and other
            
            
            80
            
            
            (36
            )
            
            (72
            )**Net
                cash provided from operating****activities**
            
            **$**
            **143**
            
            **$**
            **46**
            
            **$**
            **16**





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


(2)  Pension
      trust
      contributions in 2005 and 2004 are net of $6 million and
      $20 million


of
      income tax
      benefits, respectively.





Cash
      earnings (in
      the table above) are not a measure of performance calculated in accordance
      with
      GAAP. We believe that cash earnings 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)
            
            $
            27
            
            $
            36
            
            $
            21Non-Cash
                Charges (Credits):Provision
                for
                depreciation
            
            
            49
            
            
            47
            
            
            52Amortization
                of regulatory assets
            
            
            50
            
            
            50
            
            
            45Deferral
                of
                new regulatory assets
            
            
            (3
            )
            
            -
            
            
            -Deferred
                costs
                recoverable as regulatory assets
            
            
            (59
            )
            
            (87
            )
            
            (80
            )Deferred
                income taxes and investment tax credits*
            
            
            9
            
            
            58
            
            
            41Cumulative
                effect of accounting change
            
            
            1
            
            
            -
            
            
            (2
            )Other
                non-cash
                charges
            
            
            3
            
            
            8
            
            
            11**Cash
                earnings (Non-GAAP)**
            
            **$**
            **77**
            
            **$**
            **112**
            
            **$**
            **88**





*
            Excludes
                $20 million of deferred tax benefits from pension contributions in
                2004.





Net
      cash provided
      from operating activities increased $97 million in 2005 compared to 2004
      resulting from an increase of $116 million from working capital changes and
      a $16 million decrease in after-tax voluntary pension plan contributions,
      partially offset by a decrease of $35 million in cash earnings. The
      increase from working capital was principally due to an increase of
      $73 million in cash provided from the settlement of receivables and an
      increase in accrued taxes of $21 million. Cash earnings decreased for the
      reasons described under "Results of Operations" above. Net cash from operating
      activities increased by $30 million in 2004 compared to 2003 resulting from
      increases of $36 million from working capital changes and $24 million
      in cash earnings for the reason described under "Results of Operations" above,
      partially offset by a $30 million after-tax voluntary pension contribution
      in 2004. The increase from working capital was principally due to reduced cash
      outflows for accounts payable.


5


*Cash
      Flows From
      Financing Activities*





Net
      cash used for
      financing activities of $39 million in 2005 compares to net cash provided
      from financing activities of $76 million in 2004. The net change of
      $115 million reflects a $76 million decrease of debt financings and a
      $39 million increase in common stock dividend payments to FirstEnergy. Net
      cash provided from financing activities of $76 million in 2004 compares to
      cash used for financing activities of $49 million in 2003. The net change
      reflects a $97 million increase in borrowings and a $28 million
      decrease in common stock dividend payments to FirstEnergy. The following table
      provides details regarding new issues and redemptions during each
      year:





**Securities
                Issued or Redeemed**
            
            **2005**
            
            **2004**
            
            **2003*****(In
                millions)***New
                Issues:Pollution
                control notes
            
            $
            45
            
            $
            150
            
            $
            -Redemptions:FMB
            
            
            49
            
            
            229
            
            
            1Unsecured
                notes
            
            
            8
            
            
            -
            
            
            -$
            57
            
            $
            229
            
            $
            1Short-term
                Borrowings, net
            
            $
            20
            
            $
            163
            
            $
            (12
            )





We
      had approximately
      $35,000 of cash and temporary investments and approximately $261 million of
      short-term indebtedness as of December 31, 2005. We have authorization from
      the SEC to incur short-term debt of up to $250 million and authorization
      from the PPUC to incur money pool borrowings of up to $300 million. In
      addition, we have $75 million of available accounts receivable financing
      facilities as of December 31, 2005 from Penelec Funding, our wholly owned
      subsidiary. As
      a separate legal
      entity with separate creditors, Penelec Funding would have to satisfy its
      obligations to creditors before any of its remaining assets could be made
      available to us.





We
      will not issue
      FMB other than as collateral for senior notes, since our senior note indentures
      prohibit (subject to certain exceptions) us from issuing any debt which is
      senior to the senior notes. As of December 31, 2005, we had the capability
      to issue $ 89 million
      of
      additional senior notes based upon FMB collateral. We have no restrictions
      on
      the issuance of preferred stock.





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





Under
      the revolving
      credit facility, borrowers may request the issuance of letters of credit
      expiring up to one year from the date of issuance. The stated amount of
      outstanding letters of credit will count against total commitments available
      under the facility and against the applicable borrower’s borrowing sub-limit.
      Total unused borrowing capability under the existing credit facility and
      accounts receivable financing facilities totaled $325 million as of
      December 31, 2005.





The
      revolving credit
      facility contains financial covenants requiring each borrower to maintain a
      consolidated debt to total capitalization ratio of no more than 65%. As of
      December 31, 2005, our debt to total capitalization as defined under the
      revolving credit facility was 36%.





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, 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%.




6


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 Companies 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 Companies 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 the
      Companies to positive from stable. Fitch stated that the revision to
      FirstEnergy's outlook resulted from improved performance of its generating
      fleet
      and ongoing debt reduction.




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





**Ratings
                  of Securities**
              
              **Securities**
              
              **S&P**
              
              **Moody’s**
              
              **Fitch****FirstEnergy**
              
              
              Senior
                  unsecured
              
              
              BBB-
              
              
              Baa3
              
              
              BBB-**Penelec**
              
              
              Senior
                  unsecured
              
              
              BBB
              
              
              Baa2
              
              
              BBB







*Cash
      Flows From
      Investing Activities*





Cash
      used for
      investing activities totaled $104 million in 2005 and $123 million in
      2004. The decrease in 2005 was primarily due to a $51 million repayment to
      the NUG trust fund in 2004 (see Note 7 to Consolidated Financial Statements)
      that did not recur in 2005 and an $11 million capital transfer from FESC in
      2004, partially offset by a $56 million increase in property additions in
      2005. Cash used for investing activities totaled $123 million in 2004 and
      cash provided from investing activities totaled approximately $22 million
      in 2003. The increase in cash used was primarily related to a $117 million
      change in NUG trust activity. Cash outflows for property additions primarily
      support Penelec's energy delivery operations.





Our
      capital spending
      for the period 2006 through 2010 is expected to be about $469 million, of
      which approximately $83 million applies to 2006. The capital spending is
      primarily for property additions supporting the distribution of
      electricity.





**Contractual
      Obligations**





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





**2007-**
            
            **2009-****Contractual
                Obligations**
            
            **Total**
            
            **2006**
            
            **2008**
            
            **2010**
            
            **Thereafter*****(In
                millions)***Long-term
                debt(1)
            
            $
            479
            
            $
            -
            
            $
            -
            
            $
            159
            
            $
            320Short-term
                borrowings
            
            
            261
            
            
            261
            
            
            -
            
            
            -
            
            
            -Operating
                leases
            
            
            19
            
            
            4
            
            
            6
            
            
            5
            
            
            4Purchases(2)
            
            
            3,725
            
            
            549
            
            
            1,057
            
            
            899
            
            
            1,220Total
            
            $
            4,484
            
            $
            814
            
            $
            1,063
            
            $
            1,063
            
            $
            1,544





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


( 2)  Power
      purchases
      under contracts with fixed or minimum quantities and approximate
      timing.





**Market
      Risk
      Information**





We
      use various
      market risk sensitive instruments, including derivative contracts, primarily
      to
      manage the risk of price and interest rate fluctuations. Our Risk Policy
      Committee, comprised of members of senior management, provides general oversight
      to risk management activities throughout the company.





7


*Commodity
      Price
      Risk*





We
      are exposed to
      market risk primarily due to fluctuations in electricity, energy transmission
      and natural gas, prices. To manage the volatility relating to these exposures,
      we use a variety of non-derivative and derivative instruments, including forward
      contracts, options, futures contracts and swaps. The derivatives are used
      principally for hedging purposes. All derivatives that fall within the scope
      of
      SFAS 133 must be recorded at their fair value and marked to market. The
      majority of our derivative hedging contracts qualify for the normal purchase
      and
      normal sale exception under SFAS 133 and are therefore excluded from the
      table below. Contracts that are not exempt from such treatment include power
      purchase agreements with NUG entities that were structured pursuant to the
      Public Utility Regulatory Act of 1978. These non-trading contracts are adjusted
      to fair value at the end of each quarter, with a corresponding regulatory asset
      recognized for above-market costs. The change in the fair value of commodity
      derivative contracts related to energy production during 2005 is summarized
      in
      the following table:





**Decrease
                in the Fair Value of Derivative Contracts**
            
            **Non-Hedge**
            
            **Hedge**
            
            **Total*****(In
                millions)***Change
                in the
                fair value of commodity derivative contractsOutstanding
                net liability as of January 1, 2005
            
            $
            (368
            )
            $
            -
            
            $
            (368
            )New
                contract
                value when entered
            
            
            -
            
            
            -
            
            
            -Additions/Changes
                in value of existing contracts
            
            
            324
            
            
            -
            
            
            324Change
                in
                techniques/assumptions
            
            
            -
            
            
            -
            
            
            -Settled
                contracts
            
            
            71
            
            
            -
            
            
            71**Net
                Assets - Derivatives Contracts as of December 31,
                2005**(1)
            
            **$**
            **27**
            
            **$**
            **-**
            
            **$**
            **27****Impact
                of Changes in Commodity Derivative Contracts**(2)Income
                Statement Effects (Pre-Tax)
            
            $
            13
            
            $
            -
            
            $
            13Balance
                Sheet
                Effects:OCI
                (Pre-Tax)
            
            $
            -
            
            $
            -
            
            $
            -Regulatory
                Asset (net)
            
            $
            (382
            )
            $
            -
            
            $
            (382
            )





(1)
            Includes
                $13 million in non-hedge commodity derivative contracts, which are
                offset by a regulatory liability.


(2)
            Represents
                the
                decrease in value of existing contracts, settled contracts and changes
                in
                techniques/ assumptions.





Derivatives
      are
      included on the Consolidated Balance Sheet as of December 31, 2005 as
      follows:




**Non-Hedge**
            
            **Hedge**
            
            **Total*****(In
                millions)*****Current-**Other
                liabilities
            
            $
            -
            
            $
            -
            
            $
            -Other
                Assets
            
            
            -
            
            
            -
            
            
            -**Non-Current-**Other
                noncurrent liabilities
            
            
            -
            
            
            -
            
            
            -Other
                Deferred
                Charges
            
            
            27
            
            
            -
            
            
            27**Net
                assets**
            
            **$**
            **27**
            
            $
            -
            
            $
            27




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





**Source
                of Information****-
                Fair
                Value by Contract Year**
            
            **2006**
            
            **2007**
            
            **2008**
            
            **2009**
            
            **2010**
            
            **Thereafter**
            
            **Total*****(In
                millions)***Prices
                actively quoted(1)
            
            $
            13
            
            $
            (7
            )
            $
            -
            
            $
            -
            
            $
            -
            
            $
            -
            
            $
            6Other
                external
                sources(2)
            
            
            5
            
            
            3
            
            
            2
            
            
            -
            
            
            -
            
            
            -
            
            
            10Prices
                based
                on models
            
            
            -
            
            
            -
            
            
            (10
            )
            
            (2
            )
            
            1
            
            
            22
            
            
            11**Total****(3)**
            
            $
            18
            
            $
            (4
            )
            $
            (8
            )
            $
            (2
            )
            $
            1
            
            $
            22
            
            $
            27





(1)  Exchange
      traded.


(2)  Broker
      quote
      sheets.


(3)  Includes
      $13 million
      in non-hedge commodity derivative contracts, which are offset by a regulatory
      liability.








8


We
      perform
      sensitivity analyses to estimate our exposure to the market risk of our
      commodity positions. A hypothetical 10% adverse shift in quoted market prices
      in
      the near term on both our trading and nontrading derivative instruments would
      not have had a material effect on our consolidated financial position or cash
      flows as of December 31, 2005. We estimate that if energy commodity prices
      experienced an adverse 10% change, net income for the next twelve months would
      not change, as the prices for all commodity positions are already above the
      contract price caps.





*Interest
      Rate
      Risk*





We
      are subject to
      the inherent interest rate risks related to refinancing maturing debt by issuing
      new debt securities. Our exposure to fluctuations in market interest rates
      is
      reduced since our debt has fixed interest rates, as noted in the following
      table.





**Comparison
      of Carrying Value to Fair Value**




**There-**
              
              
              
              **Fair****Year
                  of Maturity**
              
              **2006**
              
              **2007**
              
              **2008**
              
              **2009**
              
              **2010**
              
              **after**
              
              **Total**
              
              **Value*****(Dollars
                  in millions)***AssetsInvestments
                  Other Than Cash
                and
                  Cash
                  Equivalents-Fixed
                  Income
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              $
              148
              
              **$**
              148
              
              **$**
              149Average
                  interest rate
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              4.8
              %
              
              4.8
              %LiabilitiesLong-term
                  Debt
                  and Other
                Long-Term
                  Obligations:Fixed
                  rate
              
              
              
              
              
              
              
              
              
              
              $
              100
              
              $
              59
              
              $
              275
              
              **$**
              434
              
              **$**
              453Average
                  interest rate
              
              
              
              
              
              
              
              
              
              
              
              6.1
              %
              
              6.8
              %
              
              5.8
              %
              
              6.0
              %Variable
                  rate
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              $
              45
              
              **$**
              45
              
              **$**
              45Average
                  interest rate
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              3.1
              %
              
              3.1
              %Short-term
                  Borrowings
              
              $
              261
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              **$**
              261
              
              **$**
              261Average
                  interest rate
              
              
              4.0
              %
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              4.0
              %
 *Equity Price Risk*





Included
      in nuclear
      decommissioning trusts are marketable equity securities carried at their current
      fair value of approximately $62 million and $60 million as of
      December 31, 2005 and 2004, respectively. A hypothetical 10% decrease in
      prices quoted by stock exchanges would result in a $6 million reduction in
      fair value as of December 31, 2005 (see Note 4 - Fair Value of
      Financial Instruments).





**Outlook**





All
      of our customers
      are able to select alternative energy suppliers. We continue to deliver power
      to
      homes and businesses through our existing distribution system, which remains
      regulated. The PPUC authorized our rate restructuring plan, establishing
      separate charges for transmission, distribution, generation and stranded cost
      recovery, which is recovered through a CTC. Customers electing to obtain power
      from an alternative supplier have their bills reduced based on the regulated
      generation component, and the customers receive a generation charge from the
      alternative supplier. We have a continuing responsibility, referred to as our
      PLR obligation, to provide power to those customers not choosing to receive
      power from an alternative energy supplier, subject to certain
      limits.





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





As
      of December 31,
      2005, our regulatory deferrals pursuant to the 1998 Restructuring Settlement
      (including the Phase 2 Proceedings) and the FirstEnergy/GPU Merger Settlement
      Stipulation are $48 million. This amount is subject to the pending resolution
      of
      taxable income issues associated with NUG Trust Fund proceeds.





9




Met-Ed
      and Penelec purchase a
      portion of their PLR requirements from FES through a wholesale power sales
      agreement and a portion from contracts with unaffiliated third party suppliers,
      including NUGs. Assuming continuation of these existing contractual
      arrangements, the available supply represents approximately 100% of the combined
      retail sales obligations of Met-Ed and Penelec in 2006 and 2007; almost 100%
      for
      2008; and approximately 85% for 2009 and 2010. Met-Ed and Penelec are authorized
      to defer any excess of NUG contract costs over current market prices. Under
      the
      terms of the wholesale agreement with FES, FES retains the supply obligation
      and
      the supply profit and loss risk for the portion of power supply requirements
      not
      self-supplied by Met-Ed and Penelec under their contracts with NUGs and other
      unaffiliated suppliers. This arrangement reduces Met-Ed's and Penelec's exposure
      to high wholesale power prices by providing power at a fixed price for their
      uncommitted PLR energy costs during the term of the agreement with FES. The
      wholesale agreement with FES is automatically extended for each successive
      calendar year unless any party elects to cancel the agreement by November 1
      of
      the preceding year. On November 1, 2005, FES and the other parties thereto
      amended the agreement to provide FES the right over the next year to terminate
      the agreement at any time upon 60 days notice. If the wholesale power agreement
      were terminated or modified, Met-Ed and Penelec would need to satisfy the
      portion of their PLR obligations currently supplied by FES from unaffiliated
      suppliers at prevailing prices, which are likely to be higher than the current
      price charged by FES under the agreement and, as a result, Met-Ed’s and
      Penelec’s purchased power costs could materially increase. If Met-Ed and Penelec
      were to replace the FES supply at current market power prices without
      corresponding regulatory authorization to increase their generation prices
      to
      customers, each company would likely incur a significant increase in operating
      expenses and experience a material deterioration in credit quality metrics.
      Under such a scenario, each company's credit profile would no longer support
      an
      investment grade rating for its fixed income securities. Met-Ed and Penelec
      are
      in the process of preparing a comprehensive rate filing that will address a
      number of transmission, distribution and supply issues and is expected to be
      filed with the PPUC in the second quarter of 2006. That filing will include,
      among other things, a request for appropriate regulatory action to mitigate
      adverse consequences from any future reduction, in whole or in part, in the
      availability to Met-Ed and Penelec of supply under the existing FES agreement.
      There can be no assurance, however, that if FES ultimately determines to
      terminate, or significantly modify the agreement, timely regulatory relief
      will
      be granted by the PPUC or, to the extent granted, adequate to mitigate such
      adverse consequences.




On
      January 12,
      2005, we filed a request with the PPUC for deferral of transmission-related
      costs beginning January 1, 2005, estimated to be approximately
      $4 million per month. The OCA, OSBA, OTS, MEIUG, PICA, Allegheny Electric
      Cooperative and Pennsylvania Rural Electric Association have all intervened
      in
      the case. To date no hearing schedule has been established, and we have not
      yet
      implemented deferral accounting for these costs.





In
      May 2004, the
      PPUC issued an order approving revised reliability benchmarks and standards,
      including revised benchmarks and standards for the Company. We 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 our 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.





See
      Note  7 to
      the consolidated financial statements for further details and a complete
      discussion of regulatory matters in Pennsylvania including a more detailed
      discussion of reliability initiatives, including actions by the PPUC, that
      impact us.





*Environmental
      Matters*





We
      accrue
      environmental liabilities only when we can conclude that it is probable that
      we
      have an obligation for such costs and can reasonably determine 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.





We
      have been named
      as a PRP at waste disposal sites which may require cleanup under the
      Comprehensive Environmental Responsive, Comprehension and Liability Act of
      1980.
      Allegations of disposal of hazardous substances at historical sites and the
      liability involved are often unsubstantial and subject to dispute; however,
      federal law provides that PRPs for a particular site are held liable on a joint
      and several basis. Therefore,
      environmental liabilities that are considered probable have been recognized
      on
      the Consolidated Balance Sheet as of December 31, 2005, based on estimates
      of the total costs of cleanup, our proportionate responsibility for such costs
      and the financial ability of other unaffiliated entities to pay. Total
      liabilities of approximately $3,000 have been accrued through December 31,
      2005.





See
      Note 11(B)
      to the consolidated financial statements for further details and a complete
      discussion of environmental matters.





10


*Legal
      Matters*





There
      are various
      lawsuits, claims (including claims for asbestos exposure) and proceedings
      related to our normal business operations pending against us. The other material
      items not otherwise discussed above are described in
      Note 11 to
      the consolidated financial statements.





**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.




*Goodwill*





In
      a business
      combination, the excess of the purchase price over the estimated fair values
      of
      the assets acquired and liabilities assumed is recognized as goodwill. Based
      on
      the guidance provided by SFAS 142, we evaluate our goodwill for impairment
      at least annually and would make such an evaluation more frequently if
      indicators of impairment should arise. In accordance with the accounting
      standard, if the fair value of a reporting unit is less than its carrying value
      (including goodwill), the goodwill is tested for impairment. If an impairment
      were indicated, we recognize a loss - calculated as the difference between
      the
      implied fair value of our goodwill and the carrying value of the goodwill.
      Our
      annual review was completed in the third quarter of 2005, with no impairment
      of
      goodwill indicated. The forecasts used in our evaluation of goodwill reflect
      operations consistent with our general business assumptions. Unanticipated
      changes in those assumptions could have a significant effect on our future
      evaluations of goodwill. In the year ended December 31, 2005, we adjusted
      goodwill to reverse pre-merger tax accruals due to the final resolution of
      tax
      contingencies related to the GPU acquisition. As of December 31, 2005, we
      had approximately $882 million of goodwill.





*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.





*Regulatory
      Accounting*





We
      are subject to
      regulation that sets the prices (rates) we are permitted to charge our customers
      based on 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
      ratemaking 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.





*Pension
      and
      Other Postretirement Benefits Accounting*





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





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





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





11


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 return
      on plan assets, respectively. The 2005 expected return was based upon
      projections of future returns and our pension trust investment allocation of
      approximately 63% equities, 33% bonds, 2% real estate and 2% cash. The gains
      or
      losses generated as a result of the difference between expected and actual
      return on plan assets are deferred and amortized and will increase or decrease
      future net periodic pension expense, respectively.





In
      the fourth
      quarter of 2005, FirstEnergy made a $500 million voluntary contribution to
      its pension plan (our share was $20 million). As a result of our voluntary
      contribution and the increased market value of pension plan assets, we
      recognized a prepaid benefit cost of $90 million as of December 31,
      2005. As prescribed by SFAS 87, we eliminated our additional minimum
      liability of $90 million. In addition, the entire AOCL balance was credited
      by $53 million (net of $37 million of deferred taxes) as the fair
      value of trust assets exceeded the accumulated benefit obligation as of
      December 31, 2005.





Health
      care cost
      trends have significantly increased and will affect future OPEB costs. The
      2005
      and 2004 composite health care trend rate assumptions are approximately 9-11%,
      gradually decreasing to 5% in later years. In determining our trend rate
      assumptions, we included the specific provisions of our health care plans,
      the
      demographics and utilization rates of plan participants, actual cost increases
      experienced in our health care plans, and projections of future medical trend
      rates. The effect on Penelec'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%
              
              $
              1.0
              
              $
              0.5
              
              $
              1.5Long-term
                  return on assets
              
              
              Decrease
                  by
                  0.25%
              
              $
              1.2
              
              $
              0.3
              
              $
              1.5Health
                  care
                  trend rate
              
              
              Increase
                  by
                  1%
              
              
              na
              
              $
              2.7
              
              $
              2.7
 *Long-Lived
        Assets*





In
      accordance with
      SFAS No. 144, we periodically evaluate our long-lived assets
      (principally goodwill) to determine whether conditions exist that would indicate
      that the carrying value of an asset might not be fully recoverable. The
      accounting standard requires that if the sum of future cash flows (undiscounted)
      expected to result from an asset is less than the carrying value of the asset,
      an asset impairment must be recognized in the financial statements. If
      impairment has occurred, we recognize a loss - calculated as the difference
      between the carrying value and the estimated fair value of the asset (discounted
      future net cash flows).





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





*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
      used 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.





12


**New
      Accounting Standards and Interpretations Adopted**





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





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





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





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





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





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





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





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





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





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








13


**PENNSYLVANIA
                  ELECTRIC COMPANY****CONSOLIDATED
                  STATEMENTS OF INCOME****For
                  the Years Ended December 31,**
              
              
              **2005**
              
              
              **2004**
              
              
              **2003*****(In
                  thousands)*****OPERATING
                  REVENUES (Note 2(I))**
              
              $
              1,122,025
              
              $
              1,036,070
              
              $
              974,857**OPERATING
                  EXPENSES AND TAXES:**Purchased
                  power (Note 2(I))
              
              
              620,509
              
              
              570,349
              
              
              550,155Other
                  operating costs (Note 2(I))
              
              
              257,869
              
              
              197,089
              
              
              178,393Provision
                  for
                  depreciation
              
              
              49,410
              
              
              47,104
              
              
              51,754Amortization
                  of regulatory assets
              
              
              50,348
              
              
              50,403
              
              
              44,908Deferral
                  of
                  new regulatory assets
              
              
              (3,239
              )
              
              -
              
              
              -General
                  taxes
              
              
              68,984
              
              
              68,132
              
              
              66,999Income
                  taxes
              
              
              14,167
              
              
              29,313
              
              
              22,403Total
                  operating expenses and taxes
              
              
              1,058,048
              
              
              962,390
              
              
              914,612**OPERATING
                  INCOME**
              
              
              63,977
              
              
              73,680
              
              
              60,245**OTHER
                  INCOME**
              
              
              2,568
              
              
              2,314
              
              
              1,885**NET
                  INTEREST CHARGES:**Interest
                  on
                  long-term debt
              
              
              29,540
              
              
              30,029
              
              
              29,565Allowance
                  for
                  borrowed funds used during construction
              
              
              (908
              )
              
              (248
              )
              
              (320
              )Deferred
                  interest
              
              
              -
              
              
              190
              
              
              4,553Other
                  interest
                  expense
              
              
              10,360
              
              
              9,993
              
              
              4,318Subsidiary's
                  preferred stock dividend requirements
              
              
              -
              
              
              -
              
              
              3,777Net
                  interest
                  charges
              
              
              38,992
              
              
              39,964
              
              
              41,893**INCOME
                  BEFORE CUMULATIVE EFFECT****OF
                  ACCOUNTING CHANGES**
              
              
              27,553
              
              
              36,030
              
              
              20,237Cumulative
                  effect of accounting changes (net of income taxes
                  (benefit)of
                  ($566,000)
                  and $777,000, respectively) (Note 2(G))
              
              
              (798
              )
              
              -
              
              
              1,096**NET
                  INCOME**
              
              $
              26,755
              
              $
              36,030
              
              $
              21,333The
                  accompanying Notes to Consolidated Financial Statements are an
                  integral
                  part of these statements.






14


**PENNSYLVANIA
                    ELECTRIC COMPANY****CONSOLIDATED
                    BALANCE SHEETS****As
                    of
                    December 31,**
                
                
                **2005**
                
                
                **2004*****(in
                    thousands)*****ASSETS****UTILITY
                    PLANT:**In
                    service
                
                $
                2,043,885
                
                $
                1,981,846Less
                    -
                    Accumulated provision for depreciation
                
                
                784,494
                
                
                776,9041,259,391
                
                
                1,204,942Construction
                    work in progress
                
                
                30,888
                
                
                22,8161,290,279
                
                
                1,227,758**OTHER
                    PROPERTY AND INVESTMENTS:**Nuclear
                    plant
                    decommissioning trusts
                
                
                113,368
                
                
                109,620Non-utility
                    generation trusts
                
                
                96,761
                
                
                95,991Long-term
                    notes receivable from associated companies
                
                
                17,624
                
                
                14,001Other
                
                
                15,031
                
                
                18,746242,784
                
                
                238,358**CURRENT
                    ASSETS:**Cash
                    and cash
                    equivalents
                
                
                35
                
                
                36Receivables-Customers
                    (less accumulated provision of $4,184,000 and $4,712,000respectively,
                    for uncollectible accounts)
                
                
                129,960
                
                
                121,112Associated
                    companies
                
                
                18,626
                
                
                97,528Other
                
                
                12,800
                
                
                12,778Notes
                    receivable from associated companies
                
                
                -
                
                
                7,352Prepayments
                    and other
                
                
                7,936
                
                
                7,198169,357
                
                
                246,004**DEFERRED
                    CHARGES AND OTHER ASSETS:**Goodwill
                
                
                882,344
                
                
                888,011Regulatory
                    assets
                
                
                -
                
                
                200,173Prepaid
                    pension costs
                
                
                89,637
                
                
                -Other
                
                
                24,176
                
                
                13,448996,157
                
                
                1,101,632$
                2,698,577
                
                $
                2,813,752**CAPITALIZATION
                    AND LIABILITIES****CAPITALIZATION**(See
                    Consolidated Statements of Capitalization)**:**Common
                    stockholder's equity
                
                $
                1,333,877
                
                $
                1,305,015Long-term
                    debt
                    and other long-term obligations
                
                
                476,504
                
                
                481,8711,810,381
                
                
                1,786,886**CURRENT
                    LIABILITIES:**Currently
                    payable long-term debt
                
                
                -
                
                
                8,248Short-term
                    borrowings (Note 10)-Associated
                    companies
                
                
                261,159
                
                
                241,496Accounts
                    payable-Associated
                    companies
                
                
                33,770
                
                
                56,154Other
                
                
                38,277
                
                
                25,960Accrued
                    taxes
                
                
                27,905
                
                
                7,999Accrued
                    interest
                
                
                8,905
                
                
                9,695Other
                
                
                19,756
                
                
                23,750389,772
                
                
                373,302**NONCURRENT
                    LIABILITIES:**Power
                    purchase
                    contract loss liability
                
                
                -
                
                
                382,548Regulatory
                    liabilities
                
                
                162,937
                
                
                -Retirement
                    benefits
                
                
                102,046
                
                
                118,247Asset
                    retirement obligation
                
                
                72,295
                
                
                66,443Accumulated
                    deferred income taxes
                
                
                106,871
                
                
                37,318Other
                
                
                54,275
                
                
                49,008498,424
                
                
                653,564**COMMITMENTS
                    AND CONTINGENCIES**(Notes
                    5
                    and 11)
                
                $
                2,698,577
                
                $
                2,813,752The
                    accompanying Notes to Consolidated Financial Statements are an
                    integral
                    part of these balance sheets.





15


**PENNSYLVANIA
                  ELECTRIC COMPANY****CONSOLIDATED
                  STATEMENTS OF
                  CAPITALIZATION****As
                  of
                  December 31,**
              
              
              
              
              
              **2005**
              
              **2004*****(Dollars
                  in thousands, except per***
                ***share
                  amounts)*****COMMON
                  STOCKHOLDER'S EQUITY:**Common stock, par value $20 per share, authorized 5,400,000
                shares5,290,596
                  shares outstanding
              
              
              
              
              
              
              
              $
              105,812
              
              $
              105,812Other
                  paid-in
                  capital
              
              
              
              
              
              
              
              
              1,202,551
              
              
              1,205,948Accumulated
                  other comprehensive loss (Note 2 (F))
              
              
              
              
              
              
              
              
              (309
              )
              
              (52,813
              )Retained
                  earnings (Note 8(A))
              
              
              
              
              
              
              
              
              25,823
              
              
              46,068Total
                  common
                  stockholder's equity
              
              
              
              
              
              
              
              
              1,333,877
              
              
              1,305,015**LONG-TERM
                  DEBT AND OTHER LONG-TERM OBLIGATIONS (Note 8
                  (C)):**First
                  mortgage
                  bonds:6.125%
                  due
                  2007
              
              
              
              
              
              
              
              
              -
              
              
              3,4955.350%
                  due
                  2010
              
              
              
              
              
              
              
              
              12,310
              
              
              12,3105.350%
                  due
                  2010
              
              
              
              
              
              
              
              
              12,000
              
              
              12,0005.800%
                  due
                  2020
              
              
              
              
              
              
              
              
              -
              
              
              20,0006.050%
                  due
                  2025
              
              
              
              
              
              
              
              
              -
              
              
              25,000Total
                  first
                  mortgage bonds
              
              
              
              
              
              
              
              
              24,310
              
              
              72,805Unsecured
                  notes:7.500%
                  due
                  2005
              
              
              
              
              
              
              
              
              -
              
              
              8,0006.125%
                  due
                  2009
              
              
              
              
              
              
              
              
              100,000
              
              
              100,0007.770%
                  due
                  2010
              
              
              
              
              
              
              
              
              35,000
              
              
              35,0005.125%
                  due
                  2014
              
              
              
              
              
              
              
              
              150,000
              
              
              150,0006.625%
                  due
                  2019
              
              
              
              
              
              
              
              
              125,000
              
              
              125,000*  
                  3.080% due 2020
              
              
              
              
              
              
              
              
              20,000
              
              
              -*  
                  3.030% due 2025
              
              
              
              
              
              
              
              
              25,000
              
              
              -Total
                  unsecured notes
              
              
              
              
              
              
              
              
              455,000
              
              
              418,000Capital
                  lease
                  obligations
              
              
              
              
              
              
              
              
              -
              
              
              43Net
                  unamortized discount on debt
              
              
              
              
              
              
              
              
              (2,806
              )
              
              (729
              )Long-term
                  debt
                  due within one year
              
              
              
              
              
              
              
              
              -
              
              
              (8,248
              )Total
                  long-term debt
              
              
              
              
              
              
              
              
              476,504
              
              
              481,871**TOTAL
                  CAPITALIZATION**
              
              
              
              
              
              
              
              $
              1,810,381
              
              $
              1,786,886The
                  accompanying Notes to Consolidated Financial Statements are an
                  integral
                  part of these statements.*
                  Unsecured
                  note has a variable-rate. Rate shown is the current applicable
                  rate.





16


**PENNSYLVANIA
                    ELECTRIC COMPANY****CONSOLIDATED
                    STATEMENTS OF COMMON STOCKHOLDER'S EQUITY****Accumulated****Common
                    Stock**
                
                **Other**
                
                **Other****Comprehensive**
                
                **Number**
                
                **Par**
                
                **Paid-In**
                
                **Comprehensive**
                
                **Retained****Income
                    (Loss)**
                
                **of
                    Shares**
                
                **Value**
                
                **Capital**
                
                **Income
                    (Loss)**
                
                **Earnings*****(Dollars
                    in thousands)***Balance,
                    January 1, 2003
                
                
                
                
                
                5,290,596
                
                $
                105,812
                
                $
                1,215,256
                
                $
                (69
                )
                $
                32,705Net
                    income
                
                $
                21,333
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                21,333Net
                    unrealized
                    gain on derivative instruments
                
                
                72
                
                
                
                
                
                
                
                
                
                
                
                72Minimum
                    liability for unfunded retirement benefits,net
                    of
                    $(29,908,000) of income taxes
                
                
                (42,188
                )
                
                
                
                
                
                
                
                
                
                
                (42,188
                )Comprehensive
                    loss
                
                $
                (20,783
                )Cash
                    dividends
                    on common stock
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                (36,000
                )Purchase
                    accounting fair value adjustment
                
                
                
                
                
                
                
                
                
                
                
                411Balance,
                    December 31, 2003
                
                
                
                
                
                5,290,596
                
                
                105,812
                
                
                1,215,667
                
                
                (42,185
                )
                
                18,038Net
                    income
                
                $
                36,030
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                36,030Net
                    unrealized
                    loss on investments
                
                
                (2
                )
                
                
                
                
                
                
                
                
                
                
                (2
                )Net
                    unrealized
                    loss on derivative instruments, netof
                    $(249,000)
                    of income taxes
                
                
                (353
                )
                
                
                
                
                
                
                
                
                
                
                (353
                )Minimum
                    liability for unfunded retirement benefits,net
                    of
                    $(7,298,000) of income taxes
                
                
                (10,273
                )
                
                
                
                
                
                
                
                
                
                
                (10,273
                )Comprehensive
                    income
                
                $
                25,402Cash
                    dividends
                    on common stock
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                (8,000
                )Purchase
                    accounting fair value adjustment
                
                
                
                
                
                
                
                
                
                
                
                (9,719
                )Balance,
                    December 31, 2004
                
                
                
                
                
                5,290,596
                
                
                105,812
                
                
                1,205,948
                
                
                (52,813
                )
                
                46,068Net
                    income
                
                $
                26,755
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                26,755Net
                    unrealized
                    gain on investmentsof
                    $4,000 of
                    income taxes
                
                
                3
                
                
                
                
                
                
                
                
                
                
                
                3Net
                    unrealized
                    gain on derivative instruments, netof
                    $24,000 of
                    income taxes
                
                
                40
                
                
                
                
                
                
                
                
                
                
                
                40Minimum
                    liability for unfunded retirement benefits,net
                    of
                    $37,206,000 of income taxes
                
                
                52,461
                
                
                
                
                
                
                
                
                
                
                
                52,461Comprehensive
                    income
                
                $
                79,259Restricted
                    stock units
                
                
                
                
                
                
                
                
                
                
                
                20Cash
                    dividends
                    on common stock
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                (47,000
                )Purchase
                    accounting fair value adjustment
                
                
                
                
                
                
                
                
                
                
                
                (3,417
                )Balance,
                    December 31, 2005
                
                
                
                
                
                5,290,596
                
                $
                105,812
                
                $
                1,202,551
                
                $
                (309
                )
                $
                25,823
   **CONSOLIDATED
                    STATEMENTS OF PREFERRED STOCK****Subject
                    to****Mandatory
                    Redemption****Number**
                
                **Carrying****of
                    Shares**
                
                **Value*****(Dollars
                    in thousands)***Balance,
                    January 1, 2003
                
                
                4,000,000
                
                $
                92,214FIN
                    46
                    Deconsolidation7.34%
                    Series
                
                
                (4,000,000
                )
                
                (92,428
                )Amortization
                    of fair marketvalue
                    adjustment
                
                
                
                
                
                214Balance,
                    December 31, 2003
                
                
                -
                
                
                -Balance,
                    December 31, 2004
                
                
                -
                
                
                -Balance,
                    December 31, 2005
                
                
                -
                
                $
                -The
                    accompanying Notes to Consolidated Financial Statements are an
                    integral
                    part of these statements.




17


**PENNSYLVANIA
                      ELECTRIC COMPANY****CONSOLIDATED
                      STATEMENTS OF CASH FLOWS****For
                      the Years Ended December 31,**
                  
                  **2005**
                  
                  **2004**
                  
                  **2003****(In
                      thousands)****CASH
                      FLOWS FROM OPERATING ACTIVITIES:**Net
                      income
                  
                  $
                  26,755
                  
                  $
                  36,030
                  
                  $
                  21,333Adjustments
                      to
                      reconcile net income to net cash fromoperating
                      activities -Provision
                      for
                      depreciation
                  
                  
                  49,410
                  
                  
                  47,104
                  
                  
                  51,754Amortization
                      of regulatory assets
                  
                  
                  50,348
                  
                  
                  50,403
                  
                  
                  44,908Deferral
                      of
                      new regulatory assets
                  
                  
                  (3,239
                  )
                  
                  -
                  
                  
                  -Deferred
                      costs
                      recoverable as regulatory assets
                  
                  
                  (59,224
                  )
                  
                  (87,379
                  )
                  
                  (80,126
                  )Deferred
                      income taxes and investment tax credits, net
                  
                  
                  8,823
                  
                  
                  77,375
                  
                  
                  40,112Accrued
                      compensation and retirement benefits
                  
                  
                  3,596
                  
                  
                  9,048
                  
                  
                  10,683Cumulative
                      effect of accounting changes (Note 2(G))
                  
                  
                  798
                  
                  
                  -
                  
                  
                  (1,096
                  )Pension
                      trust
                      contribution
                  
                  
                  (20,000
                  )
                  
                  (50,281
                  )
                  
                  -Decrease
                      (increase) in operating assets:Receivables
                  
                  
                  70,330
                  
                  
                  (2,591
                  )
                  
                  13,052Prepayments
                      and other current assets
                  
                  
                  (737
                  )
                  
                  (4,687
                  )
                  
                  41Increase
                      (decrease) in operating liabilities:Accounts
                      payable
                  
                  
                  (10,067
                  )
                  
                  (13,909
                  )
                  
                  (84,700
                  )Accrued
                      taxes
                  
                  
                  19,905
                  
                  
                  (705
                  )
                  
                  (4,215
                  )Accrued
                      interest
                  
                  
                  (790
                  )
                  
                  (2,999
                  )
                  
                  -Other
                  
                  
                  7,158
                  
                  
                  (11,116
                  )
                  
                  4,230Net
                      cash
                      provided from operating activities
                  
                  
                  143,066
                  
                  
                  46,293
                  
                  
                  15,976**CASH
                      FLOWS FROM FINANCING ACTIVITIES:**New
                      Financing-Long-term
                      debt
                  
                  
                  45,000
                  
                  
                  150,000
                  
                  
                  -Short-term
                      borrowings, net
                  
                  
                  19,663
                  
                  
                  162,986
                  
                  
                  -Redemptions
                      and Repayments-Long-term
                      debt
                  
                  
                  (56,538
                  )
                  
                  (228,670
                  )
                  
                  (812
                  )Short-term
                      borrowings, net
                  
                  
                  -
                  
                  
                  -
                  
                  
                  (11,917
                  )Dividend
                      Payments-Common
                      stock
                  
                  
                  (47,000
                  )
                  
                  (8,000
                  )
                  
                  (36,000
                  )Net
                      cash
                      provided from (used for) financing activities
                  
                  
                  (38,875
                  )
                  
                  76,316
                  
                  
                  (48,729
                  )**CASH
                      FLOWS FROM INVESTING ACTIVITIES:**Property
                      additions
                  
                  
                  (107,602
                  )
                  
                  (51,801
                  )
                  
                  (44,657
                  )Non-utility
                      generation trusts withdrawals (contributions)
                  
                  
                  -
                  
                  
                  (50,614
                  )
                  
                  66,327Loan
                      repayments from (loans to) associated companies, net
                  
                  
                  3,730
                  
                  
                  (7,559
                  )
                  
                  1,721Other,
                      net
                  
                  
                  (320
                  )
                  
                  (12,635
                  )
                  
                  (912
                  )Net
                      cash
                      provided from (used for) investing activities
                  
                  
                  (104,192
                  )
                  
                  (122,609
                  )
                  
                  22,479Net
                      change in
                      cash and cash equivalents
                  
                  
                  (1
                  )
                  
                  -
                  
                  
                  (10,274
                  )Cash
                      and cash
                      equivalents at beginning of year
                  
                  
                  36
                  
                  
                  36
                  
                  
                  10,310Cash
                      and cash
                      equivalents at end of year
                  
                  $
                  35
                  
                  $
                  36
                  
                  $
                  36**SUPPLEMENTAL
                      CASH FLOW INFORMATION:**Cash
                      Paid
                      During the Year-Interest
                      (net
                      of amounts capitalized)
                  
                  $
                  35,387
                  
                  $
                  40,765
                  
                  $
                  37,497Income
                      taxes
                      (refund)
                  
                  $
                  (42,324
                  )
                  $
                  (36,434
                  )
                  $
                  10,695The
                      accompanying Notes to Consolidated Financial Statements are
                      an integral
                      part of these statements.





18


**PENNSYLVANIA
                    ELECTRIC COMPANY****CONSOLIDATED
                    STATEMENTS OF TAXES****For
                    the Years Ended December 31,**
                
                
                
                **2005**
                
                **2004**
                
                **2003*****(In
                    thousands)*****GENERAL
                    TAXES:**State
                    gross
                    receipts*
                
                
                
                
                $
                58,184
                
                $
                55,390
                
                $
                53,716Real
                    and
                    personal property
                
                
                
                
                
                1,404
                
                
                2,686
                
                
                1,624Social
                    security and unemployment
                
                
                
                
                
                5,248
                
                
                5,103
                
                
                3,312Other
                
                
                
                
                
                4,148
                
                
                4,953
                
                
                8,347Total
                    general
                    taxes
                
                
                
                
                $
                68,984
                
                $
                68,132
                
                $
                66,999**PROVISION
                    FOR INCOME TAXES:**Currently
                    payable-Federal
                
                
                
                
                $
                6,652
                
                $
                (38,759
                )
                $
                (15,968
                )State
                
                
                
                
                
                571
                
                
                (8,615
                )
                
                6927,223
                
                
                (47,374
                )
                
                (15,276
                )Deferred,
                    net-Federal
                
                
                
                
                
                10,529
                
                
                64,435
                
                
                35,136State
                
                
                
                
                
                (830
                )
                
                13,959
                
                
                6,7419,699
                
                
                78,394
                
                
                41,877Investment
                    tax
                    credit amortization
                
                
                
                
                
                (876
                )
                
                (1,019
                )
                
                (988
                )Total
                    provision for income taxes
                
                
                
                
                $
                16,046
                
                $
                30,001
                
                $
                25,613**INCOME
                    STATEMENT CLASSIFICATION****OF
                    PROVISION FOR INCOME TAXES:**Operating
                    income
                
                
                
                
                $
                14,167
                
                $
                29,313
                
                $
                22,403Other
                    income
                
                
                
                
                
                2,445
                
                
                688
                
                
                2,433Cumulative
                    effect of accounting changes
                
                
                
                
                
                (566
                )
                
                -
                
                
                777Total
                    provision for income taxes
                
                
                
                
                $
                16,046
                
                $
                30,001
                
                $
                25,613**RECONCILIATION
                    OF FEDERAL INCOME TAX****EXPENSE
                    AT STATUTORY RATE TO TOTAL****PROVISION
                    FOR INCOME TAXES:**Book
                    income
                    before provision for income taxes
                
                
                
                
                $
                42,801
                
                $
                66,031
                
                $
                46,946Federal
                    income
                    tax expense at statutory rate
                
                
                
                
                $
                14,980
                
                $
                23,111
                
                $
                16,431Increases
                    (reductions) in taxes resulting from-Amortization
                    of investment tax credits
                
                
                
                
                
                (876
                )
                
                (1,019
                )
                
                (988
                )Depreciation
                
                
                
                
                
                4,005
                
                
                1,649
                
                
                2,655State
                    income
                    taxes, net of federal income tax benefit
                
                
                
                
                
                (168
                )
                
                3,474
                
                
                4,831Other,
                    net
                
                
                
                
                
                (1,895
                )
                
                2,786
                
                
                2,684Total
                    provision for income taxes
                
                
                
                
                $
                16,046
                
                $
                30,001
                
                $
                25,613**ACCUMULATED
                    DEFERRED INCOME TAXES AS OF****DECEMBER
                    31:**Property
                    basis
                    differences
                
                
                
                
                $
                308,297
                
                $
                287,234
                
                $
                284,667Non-utility
                    generation costs
                
                
                
                
                
                (177,878
                )
                
                (181,649
                )
                
                (223,350
                )Purchase
                    accounting basis difference
                
                
                
                
                
                (762
                )
                
                (762
                )
                
                (762
                )Asset
                    retirement obligations
                
                
                
                
                
                (566
                )
                
                -
                
                
                -Sale
                    of
                    generation assets
                
                
                
                
                
                7,495
                
                
                7,495
                
                
                7,495Customer
                    receivables for future income taxes
                
                
                
                
                
                55,169
                
                
                52,063
                
                
                55,817Other
                    comprehensive income
                
                
                
                
                
                (221
                )
                
                (37,455
                )
                
                (29,908
                )Deferred
                    nuclear expenses
                
                
                
                
                
                (57,469
                )
                
                (56,238
                )
                
                (47,745
                )Employee
                    benefits
                
                
                
                
                
                (17,566
                )
                
                (20,397
                )
                
                (42,368
                )Other
                
                
                
                
                
                (9,628
                )
                
                (12,973
                )
                
                (20,488
                )Net
                    deferred
                    income tax liability
                
                
                
                
                $
                106,871
                
                $
                37,318
                
                $
                (16,642
                )* 
                    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.


19


**NOTES
      TO
      CONSOLIDATED FINANCIAL STATEMENTS**





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





The
      consolidated
      financial statements include Penelec (Company) and its wholly owned
      subsidiaries. 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 subsidiaries, including OE, CEI, TE,
      ATSI, JCP&L and Met-Ed.





The
      Company follows
      GAAP and complies with the regulations, orders, policies and practices
      prescribed by the SEC, 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
      Company accounts
      for the effects of regulation through the application of SFAS 71 since its
      rates:





·
            are
                established by a third-party regulator with the authority to set
                rates
                that bind customers;





·
            are
                cost-based; and





·
            can
                be charged
                to and collected from customers.





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





*Regulatory
      Assets-*





The
      Company
      recognizes, as regulatory assets, costs which the FERC and the 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 Company’s regulatory plan. The Company continues to bill and collect
      cost-based rates for its transmission and distribution services, which remain
      regulated; accordingly, it is appropriate that the Company continue the
      application of SFAS 71 to those operations.





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





**2005**
            
            **2004*****(In
                millions)***Regulatory
                transition costs
            
            $
            (272
            )
            $
            114Customer
                receivables for future income taxes
            
            
            141
            
            
            119Nuclear
                decommissioning costs
            
            
            (47
            )
            
            (47
            )Gain/Loss
                on
                reacquired debt and other
            
            
            15
            
            
            14**Total**
            
            **$**
            (163
            )
            **$**
            **200**





Regulatory liabilities
      for
      transition costs as of December 31, 2005 include the deferral of gains
      associated with the previous divestiture of certain generation assets.
      Regulatory liabilities are reduced to the extent above-market NUG costs incurred
      exceed the amount recovered in CTC revenues. The Company's NUG power purchase
      agreements are adjusted to fair value at the end of each quarter, with a
      corresponding regulatory asset recognized for projected above-market NUG costs.
      Recovery of any remaining regulatory transition costs is expected to continue
      under the provisions of the various regulatory proceedings in
      Pennsylvania.





20


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





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





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





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





Receivables
      from
      customers include sales to residential, commercial and industrial customers
      and
      sales to wholesale customers. There was no material concentration of receivables
      as of December 31, 2005 with respect to any particular segment of the
      Company's customers. Total customer receivables were $130 million (billed -
      $80 million and unbilled - $50 million) and $121 million (billed
      - $76 million and unbilled - $45 million) as of December 31, 2005
      and 2004, respectively.





**(D)**  **PROPERTY,
      PLANT AND EQUIPMENT-**





As
      a result of the
      Company's acquisition by FirstEnergy in 2001, a portion of the Company’s
      property, plant and equipment was adjusted to reflect fair value. The majority
      of the Company’s property, plant and equipment continues to be reflected at
      original cost since such assets remain subject to rate regulation on a
      historical cost basis. The costs of normal maintenance, repairs and minor
      replacements are expensed as incurred. The Company's accounting policy for
      planned major maintenance projects is to recognize liabilities as they are
      incurred.





The
      Company provides
      for depreciation on a straight-line basis at various rates over the estimated
      lives of property included in plant in service. The annualized composite rate
      was approximately 2.6% in 2005, 2.5% in 2004 and 2.7% in 2003.





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





*Long-Lived
      Assets*





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





*Goodwill*





In
      a business
      combination, the excess of the purchase price over the estimated fair values
      of
      assets acquired and liabilities assumed is recognized as goodwill. Based on
      the
      guidance provided by SFAS 142, the Company evaluates its goodwill for
      impairment at least annually and would make such an evaluation more frequently
      if indicators of impairment should arise. In accordance with the accounting
      standard, if the fair value of a reporting unit is less than its carrying value
      (including goodwill), the goodwill is tested for impairment. If an impairment
      is
      indicated, the Company recognizes a loss - calculated as the difference between
      the implied fair value of a reporting unit's goodwill and the carrying value
      of
      the goodwill. The Company's annual review was completed in the third quarter
      of
      2005 with no impairment indicated. The
      forecasts used
      in the Company's evaluations of goodwill reflect operations consistent with
      its
      general business assumptions. Unanticipated changes in those assumptions could
      have a significant effect on the Company's future evaluations of goodwill.
      As of
      December 31, 2005, the Company had $882 million of
      goodwill. In 2005, the
      Company adjusted goodwill for the reversal of tax valuation allowances related
      to income tax benefits realized attributable to prior period capital loss
      carryforwards that were used to offset capital gains generated in 2005 and
      above-market NUGs.





*Investments*





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





21


**(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. As of December 31, 200 5,
      accumulated other
      comprehensive loss consisted of unrealized losses on derivative instrument
      hedges of $0.3 million. As of December 31, 2004, accumulated other
      comprehensive loss consisted of a minimum liability for unfunded retirement
      benefits of $52 million and unrealized losses on derivative instrument
      hedges of $1 million.





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





Results
      in 2005
      include an after-tax charge of $ 0.8 million
      recorded upon the adoption of FIN 47 in December 2005. The Company
      identified applicable legal obligations as defined under the new standard at
      its
      substation control rooms, service center buildings, line shops and office
      buildings, identifying asbestos as the primary conditional ARO. The Company
      recorded a conditional ARO liability of $1.6 million (including accumulated
      accretion for the period from the date the liability was incurred to the date
      of
      adoption), an asset retirement cost of $0.4 million (recorded as part of
      the carrying amount of the related long-lived asset) and accumulated
      depreciation of $0.2 million.





As
      a result of
      adopting SFAS 143 in January 2003, asset retirement costs were recorded in
      the amount of $93 million as part of the carrying amount of the related
      long-lived asset, offset by accumulated depreciation of $93 million. The
      ARO liability on the date of adoption was $99 million, including
      accumulated accretion for the period from the date the liability was incurred
      to
      the date of adoption. The remaining cumulative effect adjustment for
      unrecognized depreciation and accretion, offset by the reduction in the existing
      decommissioning liabilities and the reversal of accumulated estimated removal
      costs for non-regulated generation assets, was a $1.9 million increase to
      income ($1.1 million, net of tax) in the year ended December 31,
      2003.





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





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





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





Operating
      expenses
      and other income included transactions with affiliated companies, primarily
      FESC, GPUS and FES. GPUS (until it ceased operations in mid-2003) and FESC
      have
      provided legal, accounting, financial and other corporate support services
      to
      the Company. The Company purchases a portion of its PLR responsibility from
      FES
      through a wholesale power sale agreement. The primary affiliated companies
      transactions are as follows:






**2005**
                
                **2004**
                
                **2003*****(In
                    millions)*****Services
                    Received:**Power
                    purchased from FES
                
                $
                321
                
                $
                404
                
                $
                307Company
                    support services
                
                
                51
                
                
                45
                
                
                55Power
                    purchased from other affiliates
                
                
                -
                
                
                -
                
                
                5


FirstEnergy
        does not
        bill directly or allocate any of its costs to any subsidiary company. Costs
        are
        allocated to the Company from FESC, a subsidiary of FirstEnergy. The vast
        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 total for direct payroll, number of employees,
        asset balances, revenues, number of customers, other factors and specific
        departmental charge ratios. It is management’s belief that allocation methods
        utilized are reasonable. Intercompany transactions with FirstEnergy and its
        other subsidiaries are generally settled under commercial terms within thirty
        days.







22




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





FirstEnergy
      provides
      noncontributory defined benefit pension plans that cover substantially all
      of
      the Company's employees. The trusteed plans provide defined benefits based
      on
      years of service and compensation levels. The Company's funding policy is based
      on actuarial computations using the projected unit credit method. In the fourth
      quarter of 2005, FirstEnergy made a $500 million voluntary contribution to
      its pension plan (Company's share was $20 million). Projections indicated
      that absent this funding, cash contributions would have been required at some
      point prior to 2010. Pre-funding the pension plan is expected to eliminate
      this
      future funding requirement under current pension funding rules and should also
      minimize FirstEnergy's exposure to any funding requirements resulting from
      proposed pension reform.





FirstEnergy
      provides
      a minimum amount of noncontributory life insurance to retired employees in
      addition to optional contributory insurance. Health care benefits, which include
      certain employee contributions, deductibles and co-payments, are also available
      to retired employees hired prior to January 1, 2005, their dependents and,
      under certain circumstances, their survivors. The Company recognizes the
      expected cost of providing other postretirement benefits to employees and their
      beneficiaries and covered dependents from the time employees are hired until
      they become eligible to receive those benefits. In addition, FirstEnergy has
      obligations to former or inactive employees after employment, but before
      retirement for disability related benefits.





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





23


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





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





**Amounts
                Recognized in the**
              **Consolidated
                Balance Sheets**
              **As
                of
                December 31**Prepaid
                benefit cost
            
            $
            1,023
            
            $
            -
            
            $
            -
            
            $
            -Accrued
                benefit cost
            
            
            -
            
            
            (14
            )
            
            (1,057
            )
            
            (1,014
            )Intangible
                assets
            
            
            -
            
            
            63
            
            
            -
            
            
            -Accumulated
                other comprehensive loss
            
            
            -
            
            
            504
            
            
            -
            
            
            -Net
                amount
                recognized
            
            $
            1,023
            
            $
            553
            
            $
            (1,057
            )
            $
            (1,014
            )Company's
                share of net amount recognized
            
            $
            90
            
            $
            64
            
            $
            (101
            )
            $
            (92
            )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
                Category**Equity
                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





24


**Pension
                  Benefits**
              
              **Other
                  Benefits****Components
                  of Net Periodic Benefit Costs**
              
              **2005**
              
              **2004**
              
              **2003**
              
              **2005**
              
              **2004**
              
              **2003*****(In
                  millions)***Service
                  cost
              
              $
              77
              
              $
              77
              
              $
              66
              
              $
              40
              
              $
              36
              
              $
              43Interest
                  cost
              
              
              254
              
              
              252
              
              
              253
              
              
              111
              
              
              112
              
              
              137Expected
                  return on plan assets
              
              
              (345
              )
              
              (286
              )
              
              (248
              )
              
              (45
              )
              
              (44
              )
              
              (43
              )Amortization
                  of prior service cost
              
              
              8
              
              
              9
              
              
              9
              
              
              (45
              )
              
              (40
              )
              
              (9
              )Amortization
                  of transition obligation
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              9Recognized
                  net
                  actuarial loss
              
              
              36
              
              
              39
              
              
              62
              
              
              40
              
              
              39
              
              
              40Net
                  periodic
                  cost
              
              $
              30
              
              $
              91
              
              $
              142
              
              $
              101
              
              $
              103
              
              $
              177Company's
                  share of net periodic cost (income)
              
              $
              (5
              )
              $
              -
              
              $
              7
              
              $
              8
              
              $
              3
              
              $
              10
 **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 rate of return on pension plan assets consider historical market returns
      and economic forecasts for the types of investments held by the Company's
      pension trusts. The long-term rate of return is developed considering the
      portfolio’s asset allocation strategy.





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





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





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








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





As
      a result of its
      voluntary contribution and the increased market value of pension plan assets,
      the Company recognized a prepaid benefit cost of $90 million as of
      December 31, 2005. As prescribed by SFAS 87, the Company eliminated
      its additional minimum liability by $90 million. In addition, the entire
      AOCL balance was credited by $53 million (net of $37 million in
      deferred taxes) as the fair value of trust assets exceeded the accumulated
      benefit obligation as of December 31, 2005.





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


25





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





The
      Company also
      maintains an unfunded benefit plan under which non-qualified supplemental
      pension benefits are paid to certain employees in addition to amounts received
      under the Company’s qualified retirement plan, which is subject to IRS
      limitations on covered compensation. The net liability recognized was $1 million
      as of December 31, 2005.





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





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





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





**2005**
            
            **2004****Carrying**
            
            **Fair**
            
            **Carrying**
            
            **Fair****Value**
            
            **Value**
            
            **Value**
            
            **Value*****(In
                millions)***Long-term
                debt
            
            $
            479
            
            $
            498
            
            $
            491
            
            $
            521





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
      corporations with credit ratings similar to the Company’s ratings.





*Investments-*





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





**2005**
            
            **2004****Carrying**
            
            **Fair**
            
            **Carrying**
            
            **Fair****Value**
            
            **Value**
            
            **Value**
            
            **Value*****(In
                millions)***Debt
                securities:(1)࿓-Government
                obligations
            
            $
            148
            
            $
            148
            
            $
            146
            
            $
            146࿓-Corporate
                debt securities
            
            
            1
            
            
            1
            
            
            -
            
            
            -149
            
            
            149
            
            
            146
            
            
            146Equity
                securities(1)
            
            
            62
            
            
            62
            
            
            62
            
            
            62$
            211
            
            $
            211
            
            $
            208
            
            $
            208





(1)  Includes
      nuclear
      decommissioning and NUG trust investments.





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





Investments
      other
      than cash and cash equivalents include held-to-maturity securities and
      available-for-sale securities. Decommissioning trust investments are classified
      as available-for-sale. The Company has no securities held for trading purposes.
      The following table summarizes the amortized cost basis, gross unrealized gains
      and losses and fair values for decommissioning trust investments as of
      December 31:


26





**2005**
            
            **2004****Cost**
            
            **Unrealized**
            
            **Unrealized**
            
            **Fair**
            
            **Cost**
            
            **Unrealized**
            
            **Unrealized**
            
            **Fair****Basis**
            
            **Gains**
            
            **Losses**
            
            **Value**
            
            **Basis**
            
            **Gains**
            
            **Losses**
            
            **Value*****(In
                millions)***Debt
                securities
            
            $
            51
            
            $
            1
            
            $
            -
            
            $
            52
            
            $
            49
            
            $
            1
            
            $
            -
            
            $
            50Equity
                securities
            
            
            56
            
            
            7
            
            
            1
            
            
            62
            
            
            55
            
            
            7
            
            
            2
            
            
            60$
            107
            
            $
            8
            
            $
            1
            
            $
            114
            
            $
            104
            
            $
            8
            
            $
            2
            
            $
            110





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
            
            $
            69
            
            $
            102
            
            $
            41Gross
                realized
                gains
            
            
            4
            
            
            18
            
            
            1Gross
                realized
                losses
            
            
            4
            
            
            -
            
            
            -Interest
                and
                dividend income
            
            
            3
            
            
            3
            
            
            3





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, 200 5:





**Less
                Than 12 Months**
            
            **12
                Months or More**
            
            **Total****Fair**
            
            **Unrealized**
            
            **Fair**
            
            **Unrealized**
            
            **Fair**
            
            **Unrealized****Value**
            
            **Losses**
            
            **Value**
            
            **Losses**
            
            **Value**
            
            **Losses*****(In
                millions)***Debt
                securities
            
            $
            29
            
            $
            -
            
            $
            10
            
            $
            -
            
            $
            39
            
            $
            -Equity
                securities
            
            
            9
            
            
            1
            
            
            2
            
            
            -
            
            
            11
            
            
            1$
            38
            
            $
            1
            
            $
            12
            
            $
            -
            
            $
            50
            
            $
            1





The
      Company
      periodically evaluates the securities held by its nuclear decommissioning trusts
      for other-than-temporary impairment. The Company considers the length of time
      and the extent to which the security's fair value has been less than its cost
      basis and other factors to determine whether an impairment is other than
      temporary. The recovery of amounts contributed to the Company's decommissioning
      trusts are subject to regulatory acc ounting
      in
      accordance with SFAS 71. Net unrealized gains and losses are recorded as
      regulatory liabilities or assets since the difference between investments held
      in trust and the decommissioning liabilities are recovered from or refunded
      to
      customers.





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





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





Consistent
      with the
      regulatory treatment, the rentals for capital and operating leases are charged
      to operating expenses on the Consolidated Statements of Income. The Company
      had
      a capital lease for a building that expired in 2005. The Company’s most
      significant operating lease relates to the lease of vehicles. Such costs for
      the
      three years ended December 31, 2005 are summarized as follows:





**2005**
            
            **2004**
            
            **2003*****(In
                millions)***Operating
                leasesInterest
                element
            
            $
            0.7
            
            $
            0.5
            
            $
            0.5Other
            
            
            2.1
            
            
            2.3
            
            
            3.1Capital
                LeasesInterest
                Element
            
            
            -
            
            
            0.1
            
            
            0.1Other
            
            
            0.1
            
            
            0.5
            
            
            0.6Total
                rentals
            
            $
            2.9
            
            $
            3.4
            
            $
            4.3





27


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





**Operating
                Leases*****(In
                millions)***2006
            
            $
            3.52007
            
            
            3.32008
            
            
            2.72009
            
            
            2.52010
            
            
            2.2Years
                thereafter
            
            
            4.5Total
                minimum
                lease payments
            
            
            18.7





**6.**  **VARIABLE
      INTEREST ENTITIES:**





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





The
      Company has
      evaluated its power purchase agreements and determined that certain NUG entities
      may be VIEs to the extent they own a plant that sells substantially all of
      its
      output to the Company and the contract price for power is correlated with the
      plant’s variable costs of production. The Company maintains several long-term
      power purchase agreements with NUG entities. The agreements were structured
      pursuant to the Public Utility Regulatory Policies Act of 1978. The Company
      was
      not involved in the creation of, and has no equity or debt invested in, these
      entities.





The
      Company has
      determined that for all but two of these entities, the Company has no variable
      interests in the entities or the entities are governmental or not-for-profit
      organizations not within the
      scope of FIN 46R. The Company may hold variable interests in the remaining
      two entities, which sell their output at variable prices that correlate to
      some
      extent with the operating costs of the plants. As required by FIN 46R, the
      Company periodically requests the information necessary from these entities
      to
      determine whether they are VIEs or whether the Company is the primary
      beneficiary. The Company has been unable to obtain the requested information,
      which was deemed by the requested entity to be proprietary. As such, the Company
      applied the scope exception that exempts enterprises unable to obtain the
      necessary information to evaluate entities under FIN 46R. The purchased
      power costs from these entities during 2005, 2004 and 2003 were
      $28 million, $27 million and $27 million,
      respectively.





**7.**  **REGULATORY
      MATTERS:**





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





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





28


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.





In
      May 2004, the
      PPUC issued an order approving revised reliability benchmarks and standards,
      including revised benchmarks and standards for the Company. The Company 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 Company's
      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.





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





The
      Company and
      Met-Ed had been negotiating with interested parties in an attempt to resolve
      the
      merger savings issues that are the subject of remand from the Commonwealth
      Court. The Company's and Met-Ed’s combined portion of total merger savings
      during 2001 - 2004 is estimated to be approximately $51 million. In late 2005,
      settlement discussions broke off as unsuccessful. A procedural schedule was
      established by the ALJ on January 17, 2006. The companies’ initial testimony is
      due on March 1, 2006 with testimony of the other parties and additional
      testimony by the companies to be filed through October 2006. Hearings are
      scheduled for the end of October 2006 with the ALJ’s recommended decision to be
      issued in February 2007. The companies are unable to predict the outcome of
      this
      proceeding.





In
      an
      October 16, 2003 order, the PPUC approved September 30, 2004 as the
      date for the Company's NUG trust fund refunds. The PPUC order also denied its
      accounting treatment request regarding the CTC rate/shopping credit swap by
      requiring the Company to treat the stipulated CTC rates that were in effect
      from
      January 1, 2002 on a retroactive basis. On October 22, 2003, the
      Company filed an Objection with the Commonwealth Court asking that the Court
      reverse this PPUC finding; a Commonwealth Court judge subsequently denied its
      Objection on October 27, 2003 without explanation. On October 31,
      2003, the Company filed an Application for Clarification of the Court order
      with
      the judge, a Petition for Review of the PPUC's October 2 and
      October 16, 2003 Orders, and an application for reargument, if the judge,
      in his clarification order, indicates that the Company's Objection was intended
      to be denied on the merits. The Reargument Brief before the Commonwealth Court
      was filed on January 28, 2005.





As
      of December 31,
      2005, the Company's regulatory deferral pursuant to the 1998 Restructuring
      Settlement (including the Phase 2 Proceedings) and the FirstEnergy/GPU Merger
      Settlement Stipulation is $48 million. This amount is subject to the
      pending resolution of taxable income issues associated with NUG Trust Fund
      proceeds.





29




Met-Ed
      and Penelec purchase a
      portion of their PLR requirements from FES through a wholesale power sales
      agreement and a portion from contracts with unaffiliated third party suppliers,
      including NUGs. Assuming continuation of these existing contractual
      arrangements, the available supply represents approximately 100% of the combined
      retail sales obligations of Met-Ed and Penelec in 2006 and 2007; almost 100%
      for
      2008; and approximately 85% for 2009 and 2010. Met-Ed and Penelec are authorized
      to defer any excess of NUG contract costs over current market prices. Under
      the
      terms of the wholesale agreement with FES, FES retains the supply obligation
      and
      the supply profit and loss risk for the portion of power supply requirements
      not
      self-supplied by Met-Ed and Penelec under their contracts with NUGs and other
      unaffiliated suppliers. This arrangement reduces Met-Ed's and Penelec's exposure
      to high wholesale power prices by providing power at a fixed price for their
      uncommitted PLR energy costs during the term of the agreement with FES. The
      wholesale agreement with FES is automatically extended for each successive
      calendar year unless any party elects to cancel the agreement by November 1
      of
      the preceding year. On November 1, 2005, FES and the other parties thereto
      amended the agreement to provide FES the right over the next year to terminate
      the agreement at any time upon 60 days notice. If the wholesale power agreement
      were terminated or modified, Met-Ed and Penelec would need to satisfy the
      portion of their PLR obligations currently supplied by FES from unaffiliated
      suppliers at prevailing prices, which are likely to be higher than the current
      price charged by FES under the agreement and, as a result, Met-Ed’s and
      Penelec’s purchased power costs could materially increase. If Met-Ed and Penelec
      were to replace the FES supply at current market power prices without
      corresponding regulatory authorization to increase their generation prices
      to
      customers, each company would likely incur a significant increase in operating
      expenses and experience a material deterioration in credit quality metrics.
      Under such a scenario, each company's credit profile would no longer support
      an
      investment grade rating for its fixed income securities. Met-Ed and Penelec
      are
      in the process of preparing a comprehensive rate filing that will address a
      number of transmission, distribution and supply issues and is expected to be
      filed with the PPUC in the second quarter of 2006. That filing will include,
      among other things, a request for appropriate regulatory action to mitigate
      adverse consequences from any future reduction, in whole or in part, in the
      availability to Met-Ed and Penelec of supply under the existing FES agreement.
      There can be no assurance, however, that if FES ultimately determines to
      terminate, or significantly modify the agreement, timely regulatory relief
      will
      be granted by the PPUC or, to the extent granted, adequate to mitigate such
      adverse consequences.




The
      Company, ATSI,
      JCP&L, Met-Ed, and FES continue to be involved in FERC hearings concerning
      the calculation and imposition of Seams Elimination Cost Adjustment (SECA)
      charges to various load serving entities. Pursuant to its January 30, 2006
      Order, the FERC has compressed both phases of this proceeding into a single
      hearing scheduled to begin May 1, 2006, with an initial decision on or
      before August 11, 2006.





On
      January 12, 2005,
      the Company filed, before the PPUC, a request for deferral of
      transmission-related costs beginning January 1, 2005, estimated to be
      approximately $4 million per month. The OCA, OSBA, OTS, MEIUG, PICA, Allegheny
      Electric Cooperative and Pennsylvania Rural Electric Association have all
      intervened in the case. To date, no hearing schedule has been established,
      and
      the Company has not yet implemented deferral accounting for these
      costs.





On
      January 31,
      2005, certain PJM transmission owners made three filings pursuant to a
      settlement agreement previously approved by the FERC. JCP&L, Met-Ed and
      Penelec were parties to that proceeding and joined in two of the filings. In
      the
      first filing, the settling transmission owners submitted a filing justifying
      continuation of their existing rate design within the PJM RTO. In the second
      filing, the settling transmission owners proposed a revised Schedule 12 to
      the PJM tariff designed to harmonize the rate treatment of new and existing
      transmission facilities. Interventions and protests were filed on
      February 22, 2005. In the third filing, Baltimore Gas and Electric Company
      and Pepco Holdings, Inc. requested a formula rate for transmission service
      provided within their respective zones. On May 31, 2005, the FERC issued an
      order on these cases. First, it set for hearing the existing rate design and
      indicated that it will issue a final order within six months. Second, the FERC
      approved the proposed Schedule 12 rate harmonization. Third, the FERC accepted
      the proposed formula rate, subject to referral and hearing procedures. On
      June 30, 2005, the PJM transmission owners filed a request for rehearing of
      the May 31, 2005 order. The rate design and formula rate proceedings are
      currently being litigated before the FERC. If FERC accepts AEP’s proposal to
      create a “postage stamp” rate for high voltage transmission facilities across
      PJM, significant additional transmission revenues would be imposed on JCP&L,
      Met-Ed, Penelec, and other transmission zones within PJM.





**8.**  **CAPITALIZATION:**





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





In
      general, the
      Company’s first
      mortgage
      indenture restricts the payment of dividends or distributions on or with respect
      to the Company’s common stock to amounts credited to earned surplus since the
      date of its indenture. As of December 31, 2005, the Company had retained
      earnings available to pay common stock dividends of $16 million, net of
      amounts restricted under the Company’s first mortgage indenture.





**(B)**  **PREFERRED
      STOCK-**





The
      Company’s
      preferred stock a uthorization
      consists of 11.4 million shares without par value. No preferred shares are
      currently outstanding.





30


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





The
      Company's FMB
      indenture, which secures all of the Company's FMB, serve as a direct first
      mortgage lien on substantially all of the Company's property and franchises,
      other than specifically excepted property.





The
      Company has
      various debt covenants under its financing arrangements. The most restrictive
      of
      these relate to the nonpayment of interest and/or principal on debt, which
      could
      trigger a default. Cross-default provisions also exist between FirstEnergy
      and
      the Company.





Based
      on the amount
      of bonds authenticated by the Trustee through December 31, 200 5,
      the Company’s
      annual sinking fund requirements for all bonds issued under the mortgage amount
      to approximately $13million. The Company could fulfill its sinking fund
      obligation by providing bondable property additions, refundable bonds or cash
      to
      the Trustee.





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








***(In
                millions)***2006
            
            $-2007
            
            -2008
            
            
            -2009
            
            
            1002010
            
            
            59





The
      Company’s
      obligations to repay certain pollution control revenue bonds are secured by
      several series of FMB.
      Certain
      pollution control revenue bonds are entitled to the benefit of noncancelable
      municipal bond insurance policies of $69 million to pay principal of, or
      interest on, the pollution control revenue bonds. To the extent that drawings
      are made under the policies, the Company is entitled to a credit against its
      obligation to repay that bond. For the pollution control revenue bonds issued
      in
      2005, the Company pays annual fees of 0.16% of the amount of the policy to
      the
      insurer. The Company is obligated to reimburse the insurers for any drawings
      thereunder.





**9.**
            **ASSET
                RETIREMENT OBLIGATIONS**





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





The
      Company
      initially identified applicable legal obligations as defined under the standard
      for nuclear power plant decommissioning of TMI-2. The ARO liability as of the
      date of adoption was $99 million, including accumulated accretion for the
      period from the date the liability was incurred to the date of adoption. The
      Company’s share of the obligation to decommission these units was developed
      based on site specific studies performed by an independent engineer. The Company
      utilized an expected cash flow approach to measure the fair value of the nuclear
      decommissioning ARO.





In
      2004, the Company
      revised the ARO associated with TMI-2 as the result of an updated study and
      the
      anticipated operating license extension for TMI-1. The abandoned TMI-2 is
      adjacent to TMI-1 and the units are expected to be decommissioned concurrently.
      The net decrease in the TMI-2 ARO liability and corresponding regulatory asset
      was $44 million.





The
      Company
      maintains the nuclear decommissioning trust funds 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
      $113 million.





The
      Company
      implemented FIN 47, "Accounting for Conditional Asset Retirement
      Obligations", an interpretation of SFAS 143 on December 31, 2005.
      FIN 47 provides accounting standards for conditional retirement obligations
      associated with tangible long-lived assets, requiring recognition of the fair
      value of a liability for an ARO in the period in which it is incurred if a
      reasonable estimate can be identified. FIN 47 states that an **** obligation
      exists
      even though there may be uncertainty about timing or method of settlement
      and **** further
      clarifies
      SFAS 143, stating that the uncertainty surrounding the timing and method of
      settlement when settlement is conditional on a future event occurring should
      be
      reflected in the measurement of the liability not in the recognition of the
      liability. Accounting for conditional ARO under FIN 47 is the same as
      described above in SFAS 143.





31


The
      Company
      identified applicable legal obligations as defined under the new standard at
      its
      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 $1.6 million (including accumulated accretion for the period
      from the date the liability was incurred to the date of adoption), an asset
      retirement cost of $0.4 million (recorded as part of the carrying amount of
      the
      related long-lived asset), and accumulated depreciation of $0.2 million. As
      a result, the Company recorded a $1.4 million cumulative effect adjustment
      ($0.8 million, net of tax) for unrecognized depreciation and accretion as
      of December 31, 2005. The
      costs of
      remediation were based on costs incurred during recent remediation projects
      performed at each of these locations. The conditional ARO liability was the
      developed utilizing an expected cash flow approach (as discussed in SFAC 7)
      to measure the fair value of the ARO. The Company used a probability weighted
      analysis to estimate when remediation payments would begin. The effect on income
      as if FIN 47 had been applied during 2004 and 2003 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
            
            $
            66
            
            $
            105Accretion
            
            
            4
            
            
            5Revisions
                in
                estimated cash flows
            
            
            -
            
            
            (44
            )FIN
                47
                ARO
            
            
            2
            
            
            -Balance
                at end
                of year
            
            $
            72
            
            $
            66





**10.**  **SHORT-TERM
      BORROWINGS:**





Short-term
      borrowings outstanding as of December 31, 2005, consisted of
      $261 million of borrowings from affiliates. Penelec Funding, a wholly owned
      subsidiary of Penelec, is a limited liability company whose borrowings are
      secured by customer accounts receivable purchased from Penelec. It can borrow
      up
      to $75 million under a receivables financing arrangement at rates based on
      certain bank commercial paper and is required to pay an annual facility fee
      of
      0.15% on the entire finance limit. This financing arrangement expires on
      June 29, 2006. As a separate legal entity with separate creditors, it would
      have to satisfy its obligations to creditors before any of its remaining assets
      could be made available to the Company.





In
      June 2005,
      the Company, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, FES and ATSI, as
      Borrowers, entered into a syndicated $2 billion five-year revolving credit
      facility with a syndicate of banks that expires in June 2010. Borrowings under
      the facility are available to each Borrower separately and mature on the earlier
      of 364 days from the date of borrowing or the commitment expiration date, as
      the
      same may be extended. The Company's borrowing limit under the facility is
      $250 million. The average interest rate on short-term borrowings
      outstanding as of December 31, 2005 and 2004, was 4.0% and 2.0%,
      respectively.





**11.**  **COMMITMENTS,
      GUARANTEES 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 present
      ownership interest in TMI-2, the Company is exempt from any potential assessment
      under the industry retrospective rating plan.





The
      Company is also
      insured as to its interest in TMI-2 under a policy issued to the operating
      company for the plant. Under this policy, $150 million
      is
      provided for property damage and decontamination and decommissioning costs.
      Under this policy, the Company can be assessed a maximum of approximately
      $0.2 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 property damage, decontamination, decommissioning,
      repair and replacement costs and other such costs arising from a nuclear
      incident at TMI-2 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 it concludes 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.





32


The
      Company has been
      named as a PRP at waste disposal sites, which may require cleanup under the
      Comprehensive Environmental Response, Compensation, and Liability Act of 1980.
      Allegations of disposal of hazardous substances at historical sites and the
      liability involved are often unsubstantiated and subject to dispute; however,
      federal law provides that all PRPs for a particular site are liable on a joint
      and several basis. Therefore, environmental liabilities that are considered
      probable have been recognized on the Consolidated Balance Sheet as of
      December 31, 2005, based on estimates of the total costs of cleanup, the
      Company’s proportionate responsibility for such costs and the financial ability
      of other unaffiliated entities to pay. Total liabilities of approximately $3,000
      have been accrued through December 31, 2005.





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





*Power
      Outages
      and Related Litigation*





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





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





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





*Legal
      Matters*





Various
      lawsuits,
      claims (including claims for asbestos exposure) and proceedings related to
      the
      Company's normal business operations are pending against the Company, the most
      significant of which are described above.





33


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





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





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





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





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





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





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





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





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





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





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





34


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





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





**Three
                Months Ended**
            
            **March
                31,**
              **2005**
            
            **June
                30,**
              **2005**
            
            **September
                30,**
              **2005**
            
            **December
                31,**
              **2005*****(In
                millions)***Operating
                Revenues
            
            $
            293.9
            
            $
            262.0
            
            $
            290.4
            
            $
            275.6Operating
                Expenses and Taxes
            
            
            263.8
            
            
            246.1
            
            
            284.3
            
            
            263.9Operating
                Income
            
            
            30.1
            
            
            15.9
            
            
            6.1
            
            
            11.7Other
                Income
            
            
            0.8
            
            
            (0.3
            )
            
            1.1
            
            
            1.1Net
                Interest
                Charges
            
            
            9.5
            
            
            9.8
            
            
            9.6
            
            
            10.1Income
                (Loss)
                Before Cumulative Effect
            
            
            21.4
            
            
            5.8
            
            
            (2.4
            )
            
            2.7Cumulative
                Effect of Accounting Change
            
            
            -
            
            
            -
            
            
            -
            
            
            (0.8
            )Net
                Income
                (Loss)
            
            $
            21.4
            
            $
            5.8
            
            $
            (2.4
            )
            $
            1.9








**Three
                Months Ended**
            
            **March
                31,**
              **2004**
            
            **June
                30,**
              **2004**
            
            **September
                30,**
              **2004**
            
            **December
                31,**
              **2004*****(In
                millions)***Operating
                Revenues
            
            $
            256.4
            
            $
            242.2
            
            $
            254.3
            
            $
            283.1Operating
                Expenses and Taxes
            
            
            240.9
            
            
            229.3
            
            
            226.9
            
            
            265.3Operating
                Income
            
            
            15.5
            
            
            12.9
            
            
            27.4
            
            
            17.8Other
                Income
            
            
            -
            
            
            0.4
            
            
            1.3
            
            
            0.7Net
                Interest
                Charges
            
            
            9.8
            
            
            10.2
            
            
            10.5
            
            
            9.4Net
                Income
            
            $
            5.7
            
            $
            3.1
            
            $
            18.2
            
            $
            9.1









35